Beyond the Fracking Wars : A Guide for Lawyers, Public Officials, Planners, and Citizens 9781627221641, 9781627221634

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Lower 48 States Shale Plays

Source: Energy Information Administration based on data from various published studies. Updated: May 9, 2011

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BEYOND THE FRACKING WARS A Guide for Lawyers, Public Officials, Planners, and Citizens

ERICA LEVINE POWERS AND BETH E. KINNE, EDITORS

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Cover by Monica Alejo/ABA Publishing. The materials contained herein represent the views of each chapter author in his or her individual capacity and should not be construed as the views of the author’s firm, employer, or clients, or of the editors or other chapter authors, or of the American Bar Association or the Section of State and Local Government Law unless adopted pursuant to the bylaws of the Association. Nothing contained in this book is to be considered as the rendering of legal advice for specific cases, and readers are responsible for obtaining such advice from their own legal counsel. This book is intended for educational and informational purposes only. © 2013 American Bar Association. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without the prior written permission of the publisher. For permission, contact the ABA Copyrights and Contracts Department by e-mail at [email protected] or fax at 312-988-6030, or complete the online request form at http://www.americanbar.org/utility/reprint.html. Library of Congress Cataloging-in-Publication Data Beyond the fracking wars / edited by Erica Levine Powers and Beth E. Kinne. — First edition. 4

pages cm Includes bibliographical references and index. e-ISBN: 978-1-62722-164-1 1. Hydraulic fracturing—Law and legislation—United States. I. Powers, Erica Levine, editor of compilation. II. Kinne, Beth, editor of compilation. III. American Bar Association. Section of State and Local Government Law, sponsoring body. KF1849.A2B49 2013 343.7307'72—dc23 2013036889 Discounts are available for books ordered in bulk. Special consideration is given to state bars, CLE programs, and other bar-related organizations. Inquire at ABA Publishing, American Bar Association, 321 North Clark Street, Chicago, Illinois 60654-7598. www.ShopABA.org

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For Llew E.L.P. For Rowan, Linnea, and Calla B.E.K.

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Summary of Contents Foreword About the Editors About the Contributors Preface Acknowledgments PART 1: Technology and Industry Overview 1

The Technology of Oil and Gas Shale Development — Beth E. Kinne

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The Oil and Gas Industry — Erica Levine Powers and Adam J. Yagelski

PART 2: Legal Issues 3

Leasing Mineral Rights — Chad J. Lee and Jill D. Cantway

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Oil and Gas Exploration without Leases — Christopher Denton

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Getting Gas to the People — Suedeen Kelly and Vera Callahan Neinast

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Anticipating Problems — Heather M. Urwiller

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Clearing the Air — Beth E. Kinne

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Western Water Law — Kevin Patrick and Laurie Stern

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A Riparian Rights Perspective — Adam J. Yagelski

PART 3: Nongovernmental, Governmental, Community, and Industry Perspectives: Case Studies 10

Fractured — Lisa Wozniak, Drew YoungDyke, and Jacque Rose

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Man Camps, Boomtowns, and the Boom-andBust Cycle — Sorell E. Negro

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Getting Ahead of Drilling Companies in the Haynesville Shale — Charles C. Grubb

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Backyard Drilling — Terrence S. Welch An Industry Perspective from Texas — R. Kinnan Golemon

PART 4: Critical Issues: Getting Beyond the “Fracking Wars” 15

Resolving the Fracking Wars through Planning and Stakeholder Engagement — Kenneth J. Warren

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The International Community’s Response to Hydraulic Fracturing and a Case for International Oversight — Benjamin E. Griffith

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Shareholder Engagement as a Tool for Risk Management and Disclosure — Richard A. Liroff

Index

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Contents Foreword About the Editors About the Contributors Preface Acknowledgments PART 1: Technology and Industry Overview 1

The Technology of Oil and Gas Shale Development Beth E. Kinne Identifying and Mapping the Target Formation Supporting Infrastructure: Pad Sites, Processing Plants, Pipelines, and Storage Pad Sites Roads Drilling and Casing the Well Fracturing the Formation

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Roads,

Managing Wastewater Bringing a Natural Gas Well Online Processing Plants Pipelines and Compressor Stations Storage Reworking Unconventional Wells Reclamation Conclusion 2

The Oil and Gas Industry Erica Levine Powers and Adam J. Yagelski Introduction What Comprises the Shale Oil and Gas Industry? Operators Private vs. Nationally Controlled Oil Companies Oilfield Services Companies Putting It Together Cross-Indemnification and Risk Apportionment

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Regional Diversity Best Practices Best Practices and Regional Variation Beyond Best Practices Conclusion PART 2: Legal Issues 3

Leasing Mineral Rights Chad J. Lee and Jill D. Cantway Introduction Mineral Interest Ownership Leasing in General Lease Forms and the Myth of the “Producer’s 88” Basic Private (Fee) Leases The Granting Clause The Habendum (Term) Clause The Drilling Delay Rental Clause The Royalty Clause

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Other Important Lease Terms Warranty Clauses Shut-In Clauses Pooling and Unitization Pugh Clauses Force Majeure Clauses Implied Covenants of Oil and Gas Leases Special Lease Fracturing

Considerations

for

Hydraulic

A Note on Negotiation Technique Surface Use Conditions in Oil and Gas Leases Conclusion 4

Oil and Gas Exploration without Leases Christopher Denton Introduction Origins of the Rule of Capture Consequences of the Application of the Rule of Capture

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Solutions to the Adverse Economic Consequences of the Rule of Capture Introduction to Compulsory Integration in New York State Compensating Integration

a

Landowner

in

Compulsory

The Mathematics of Compulsory Integration Conclusion 5

Getting Gas to the People Suedeen Kelly and Vera Callahan Neinast Overview The Natural Gas Act of 1938 What Types of Pipelines Are There, and How Are They Regulated? Production Pipelines Gathering Pipelines Transmission Pipelines Local Distribution Pipelines Storage Facilities

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What Type of Regulatory Approval Process Is Required to Construct a Pipeline? The FERC Process How Can the Public Effectively Convey Concerns about Proposed Pipeline Projects? What Are the Opportunities for Public Involvement in a FERC Certificate Proceeding? What Criteria Does the FERC Use to Evaluate a Project? Case Study 6

Anticipating Problems Heather M. Urwiller Performance Bonds Insurance Road Maintenance Agreements

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Clearing the Air Beth E. Kinne Air Pollution from Oil and Gas Drilling

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Health Impacts of Emissions from Oil and Gas Drilling Key Emission Reduction Technologies Green Completions Plunger Lift Systems Other Opportunities for Emissions Reductions The Regulatory Framework The 2012 Federal Air Regulations for the Oil and Gas Industry Self-Regulation through Voluntary Programs Air Emissions Regulation Approaches Taken by States

and

Monitoring

Conclusion 8

Western Water Law Kevin Patrick and Laurie Stern Introduction Hydraulic Fracturing’s Consumption

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Water

Needs

and

Hydraulic Fracturing and Water Challenges in the West How Is Hydraulic Fracturing Regulated? A Look at Select Western States Moving Forward Conclusion 9

A Riparian Rights Perspective Adam J. Yagelski Introduction Water Demand Reliance on Surface Water Sources Ecological and Social Impacts Water Withdrawal Regulation in the Marcellus Shale Region Inconsistent Regulation of Water Withdrawals Lack of Comprehensive Regulation Recommendations for New York Conclusion Recommended Resources 17

PART 3: Nongovernmental, Governmental, Community, and Industry Perspectives: Case Studies 10

Fractured Lisa Wozniak, Drew YoungDyke, and Jacque Rose Introduction History of Hydraulic Fracturing in Michigan Environmental Issues and Regulations Political Climate and Advocacy The Next Steps in Hydraulic Fracturing Technology and Policy in Michigan Conclusion

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Man Camps, Boomtowns, and the Boom-andBust Cycle Sorell E. Negro Jobs Galore … Right? Housing Demands and Shortages Trucks, Traffic, and Roads Local Government Administration Services: In the Pressure Cooker

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and

Public

What Happens When the Drilling Stops? Conclusion: Plan, Monitor, Adapt, and Repeat 12

Getting Ahead of Drilling Companies in the Haynesville Shale Charles C. Grubb General Operation of Wells Comprehensive Noise Regulations Road Usage Restrictions Water Enforcement Lessons Learned

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Backyard Drilling Terrence S. Welch Moratorium or No Moratorium? Is Local Regulation of Natural Gas Drilling a Traditional Zoning Matter or an Administrative Approval Issue? Controversial Issues in the Regulation of Municipal Gas Drilling

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Natural Gas Well Distance Setbacks Drilling in Floodplains Drilling in Public Parks Subsequent Property Development Saltwater Disposal Wells Regulation of Water Sources Necessary for Natural Gas Drilling Impacts of Natural Gas Drilling Activities on Roadway Infrastructure Conclusion 14

An Industry Perspective from Texas R. Kinnan Golemon The “Shale Gale” Groundwater Contamination Consumptive Water Use Water Quality Management Air Quality Considerations Earthquakes

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Landscape and Community Impacts Shale Oil and Gas Industry Is Reshaping the U.S. Energy Industry and Economy Significant Economic Benefits for State and Local Governments Conclusion PART 4: Critical Issues: Getting Beyond the “Fracking Wars” 15

Resolving the Fracking Wars through Planning and Stakeholder Engagement Kenneth J. Warren Introduction Policy Debate Government Response Working Toward a Consensus Model

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The International Community’s Response to Hydraulic Fracturing and a Case for International Oversight Benjamin E. Griffith Introduction

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Sustainable Energy and Water Resources Hydraulic Fracturing Comes to Europe Europe’s Shale Gas Reserves Reactions within the EU and in Other Nations International Treaties and Protocols Conclusion 17

Shareholder Engagement as a Tool for Risk Management and Disclosure Richard A. Liroff Social License to Operate and Shareholder Advocacy Investor Information Needs and the Business Case for Best Practices Extracting the Facts—Investor Disclosure Guidelines Guidelines in Practice—A Case Study of Promoting Chemical Toxicity Reduction The Future Course of Corporate Reporting on Shale Gas Operations Shareholder Advocacy—The Letter, Dialogue, and Resolution Process

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The Evolving Context of Investor Engagement Index

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Foreword The publication of Beyond the Fracking Wars by the American Bar Association will add to the dialogue about whether the United States should embrace the development of hydrocarbons that have been trapped within underground shale formations. The publication coincides with the recent death of George Mitchell, the owner and founder of Mitchell Oil & Gas Co., who is widely regarded as one of the most important, if not the most important, “father” of the development of unconventional shale oil and gas deposits in the United States. Through his vision and the commitment of the resources of his production company, Mr. Mitchell showed the world that unconventional shale oil and gas deposits could be technologically and economically developed. His efforts to produce shale gas in the Barnett Shale reservoir in North Texas opened the way for widespread shale development in the United States as well as in the rest of the world. The development of unconventional shale oil and gas is the product of the refinement of technologies that have been widely used in the oil and gas industry for nearly 80 years. Hydraulic fracturing has been regularly employed in conventional oil and gas fields since the 1940s. Injecting fluids, and/or gases in order to increase the productivity of oil and gas wells is an even older technology, dating back to the use of nitroglycerin in the oil fields of the Appalachian Basin in the early part of the

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20th century. Likewise, the refinement of horizontal drilling techniques that have been around for decades has allowed oil and gas producers to extend horizontal laterals for several miles, thus allowing greater production from the shale formation. All of these technological developments were harnessed by Mr. Mitchell to prove to the skeptical oil and gas community that unconventional shale oil and gas deposits could be developed. In the 8 or 9 years following the successes of Mitchell Oil & Gas in the Barnett Shale, unconventional shale oil and gas production is fast becoming the predominant source of hydrocarbon production in the United States. A look at the widely disseminated Energy Information Administration’s map of shale plays in the United States is illustrative of the public policy issues that will face us in the coming decades. Many states that did not have an active and vibrant oil and gas industry are now contemplating such development, with its attendant externalities, both positive and negative. Given our well-deserved attention to the issue of global warming, carbon footprints, and continued dependence on fossil fuels to provide much of the world’s energy needs, the development of shale oil and gas resources is not a risk-free alternative. Furthermore, unconventional shale oil and gas development, as with any other industrial or extractive activity, has environmental impacts that need to be addressed. Beyond the Fracking Wars attempts to educate the reader about such choices and how both governmental and nongovernmental organizations, as well as the industry, are trying to resolve these critically important public policy concerns. 25

The understanding of basic oil and gas law principles is a necessary starting point to understand shale oil and gas development in the United States. In contrast with most of the rest of the world, the United States recognizes private ownership of mineral resources and further allows that the mineral estate may be “severed” from the surface estate into two coequal estates. This creates a basic tension between surface and mineral owners where the surface owner is receiving no financial benefits from the exploitation of the mineral estate, yet is burdened by an easement that allows the mineral owner or its lessee to use the surface estate to access the minerals. Because of the private ownership of the mineral estate, development or nondevelopment decisions are made by individuals who need to balance the benefits and harms of such development on a micro and not a macro basis. Additionally since both the United States and state constitutions protect private property interests from being taken without the payment of just compensation, regulatory programs seeking to achieve macro publicpolicy objectives must consider the potential for constitutional limits on such programs. Where the government owns the minerals, as it does over a significant portion of the western United States and throughout the rest of the world, the decisions to control or limit development are made by the appropriate governmental authority and are more likely to consider broader public-policy factors than when such decisions are made by private property owners. Nonetheless, given the experience of the Bureau of Land Management’s (BLM) lengthy rulemaking process relating to the use of

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hydraulic fracturing on public lands in the United States, it is not clear that governmental ownership of the minerals will necessarily lead to a “rational” decisionmaking process. BLM is the principal federal agency dealing with oil and gas development on public lands, including the national forests. BLM management of both the surface and mineral estates over the past 100 years is marked by inconsistent and changing policy decisions, off-again and on-again mandates from Congress, and distrust from all of the stakeholders in public land management decisions. Unconventional shale oil and gas resource development creates a number of conflicts, including the one mentioned above regarding the interests of severed surface and mineral owners. One basic issue is whether or not such resources should be exploited at all. France and Vermont as well as a number of sub-state governmental units have opted for the no-development choice. New York has prohibited hydraulic fracturing operations for nearly 5 years as it explores the benefits and costs of such development. In the United States where private ownership of minerals is the norm, the rule of capture essentially deprives a mineral owner of the no-develop option because that owner’s minerals may be drained into a neighbor’s wellbore without liability. By contrast, where you have national ownership of mineral resources, including oil and gas, development of the resources, at least in theory, can be planned so as to maximize the total amount of recovered hydrocarbons in the most economically efficient manner while also taking into account other public policy considerations, such as

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environmental protection, impact on indigenous peoples, and lack of appropriate infrastructure. Due to the negative externalities associated with a rule of capture ownership regime, states began to regulate oil and gas activities starting in the latter part of the 19th century. By the early part of the 20th century, most states had adopted minimum well-spacing requirements and compulsory pooling and unitization statutes in order to prevent the over-drilling and loss of reservoir pressure that accompanied the rule of capture ownership regime. These statutes were designed to prevent waste, protect correlative rights, and conserve natural resources. As applied to conventional vertical wells that drained substantial acreage typically in a circular pattern from the wellbore, such conservation programs led to more efficient development even in the face of a nonconsenting mineral owner’s choice not to have its minerals developed. With the widespread use of horizontal wells, however, the existence of nonconsenting owners creates more difficult technological and/or economic problems with development since it is very expensive and inefficient for horizontal wellbores to make turns in order to avoid encroaching upon the lands of the nonconsenting owner. State regulatory schemes have been slow to change from a vertical well mindset to the horizontal well reality of unconventional shale oil and gas development that can, in turn, make such development less efficient. Unconventional shale oil and gas development has also created or exacerbated conflicts between different levels of government in the United States. Other than lands 28

owned by the federal government, the United States has been a minor player in the regulation of the exploration and production of oil and gas. Through the Natural Gas Act and various subsequent statutory enactments, the United States has been the principal regulator of downstream activities including transportation and storage of natural gas. Preemption issues have arisen over time relating to state regulation that invades the province of federal regulation. With unconventional shale oil and gas development, the principal conflict point appears to be with the Federal Energy Regulatory Commission’s power to license the import and export of liquefied natural gas (LNG) as well as its licensing power to authorize the construction of LNG import or export facilities. Those debates are just now starting but they are likely to become more intense in the future since there is no consensus on the impact of allowing LNG exports on the domestic natural gas market. Additionally, other federal statutes have created exemptions from federal regulatory programs, such as the Safe Drinking Water Act, and they come into play when you are engaged in unconventional shale oil and gas development. Whether these exemptions get repealed, modified, or continued will undoubtedly impact state and sub-state regulation of such development. Historically, state oil and gas conservation agencies have been the principal regulator of upstream oil and gas operations that include the exploration for, and production of, oil and gas. Nonetheless, sub-state governmental units have, for nearly 100 years, also been involved in regulating oil and gas operations. The first statutory pooling regulation was adopted by a pair of municipalities 29

in Kansas in the 1910s to deal with the surface impact of the development of oil and gas on residential lots. Communities in Oklahoma and Texas have been applying their zoning regulations to oil and gas operations for more than 50 years. However, with the shale oil and gas development boom of the past several years, sub-state units have been much more actively engaged in regulating oil and gas operations, including having both temporary and permanent moratoria placed on such operations. Sub-state governmental units can also attempt to regulate through the imposition of performance standards, the most prevalent being setback requirements for wells and/or well pads. These types of regulatory programs usually entail a permit requirement that may be discretionary in nature. Thus merely because an oil and gas operator has a drilling permit issued by the state oil and gas conservation agency does not necessarily mean that the operator can drill at the permitted location. This tension between state and sub-state units is often resolved through the courts by the application of the three principal preemption doctrines—express preemption, implied preemption by occupation of the field, and implied preemption by conflict. State legislatures historically have enacted legislation that expressly preempts sub-state units from regulating. This power is a subset of the generally accepted view that—subject to state constitutional limitations, such as prohibitions against the enactment of local laws, and home rule provisions—sub-state units are the “creatures” of the state. Exercise of this express preemption power, however, has been reasonably rare and when so exercised 30

has often been limited as to specific units of local government or as to certain types of regulation. Only Louisiana and Ohio appear to have broad express preemption provisions while Kansas and Wyoming have more limited express preemption provisions. The Pennsylvania Legislature, which recently attempted to more clearly define the preemptive powers of the Commonwealth, has been thwarted by an opinion of the Pennsylvania Commonwealth Court invalidating the key provisions of the statute. At the time of the publication of this foreword, the Pennsylvania Supreme Court has not issued an opinion on the validity of that statute. Even though all of the other oil and gas producing states do not have express preemption provisions, courts may still find preemption through two judicially-crafted doctrines. The first is the implied preemption by occupation of the field doctrine and the second is the implied preemption by conflict doctrine. Both require judicial determinations of the “implied” intent of the legislature to preempt sub-state unit powers in the absence of an express provision. The results of the application of these two doctrines to oil and gas operations have been inconsistent at best, depending on ad hoc analyses of ordinances, statutes, and regulations. Beyond the Fracking Wars tries to inform the readers of many, but not all, of the potential issues, conflicts, and processes involved in the development of unconventional shale oil and gas resources. It is an invaluable resource for anyone who is concerned about such development. The editors, the contributors, and the ABA Section of State and Local Government Law are to be applauded for their 31

efforts to educate lawyers, public officials, planners, and the public about the myriad issues that surround unconventional shale oil and gas development. Bruce M. Kramer Maddox Professor of Law Emeritus Texas Tech University School of Law Thompson Visiting Professor University of Colorado Law School

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About the Editors Erica Levine Powers is a land use and environmental lawyer with a strong interest in transitional and alternative energy. She first became involved in land use and environmental law in 1980 as an appointed volunteer member of the Concord (MA) Natural Resources Commission and incorporated this interest into her law practice. A cum laude graduate of Harvard College in Modern European History and Literature (1965), she holds J.D. (1971) and LL.M. in Taxation (1976) degrees from Boston University School of Law. Initially counsel to the Massachusetts Commissioner of Banks and then a corporate transactional lawyer at Gaston Snow & Ely Bartlett, Boston (MA), she served as counsel to the Deputy Mayor/Collector Treasurer of the City of Boston and as General Counsel to the Massachusetts Department of Food & Agriculture. She is admitted in Massachusetts, Maryland, and New York, and resides in Albany, New York. Her university-level teaching, including sabbatical coverage at the University of Iowa, Iowa State University, Cornell University, and Massey University in New Zealand, reflects and draws on the depth and breadth of her law practice. As a lecturer at the University at Albany (SUNY) for five years, she taught law and environmental planning courses in the Master in Regional Planning

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program in the Department of Geography and Planning, where she developed an environmental planning seminar on hydraulic fracturing in the Marcellus Shale. On a national level, she has participated in panels and webinars on natural gas exploration and hydraulic fracturing for the American Bar Association, the American Planning Association, and the Institute for Energy Law. She writes on land use and transportation, as well as natural gas exploration and development. In the ABA’s Section of State and Local Government Law, she is editor of the quarterly State and Local Law News and serves on the Publications Oversight Board and the Land Use Committee. In the New York State Bar Association, she co-chairs the Committee on Coastal and Wetland Resources of the Environmental Law Section.

Beth E. Kinne is an Assistant Professor of Environmental Studies at Hobart and William Smith Colleges, in Geneva, New York, where she teaches environmental law, natural resource law, global water issues, and business law. She also teaches the senior capstone course for majors in environmental studies, with a recent focus on understanding and communicating the complex issues surrounding the development of the Marcellus Shale in New York State. In July 2011, she co-chaired a conference, Proactive Approaches to Mitigating Impacts of Marcellus Shale Development, at the Finger Lakes Institute, Hobart and William Smith Colleges. She is currently guest-editing a special issue, on the Marcellus

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Shale, of the Journal of Environmental Studies and Science. Before joining the Hobart and William Smith faculty, she worked as a municipal and water rights attorney in Garfield County, Colorado from 2005 to 2008. She is admitted to practice in Washington State, Colorado, and New York. She serves on the Board of Trustees of the National Youth Science Foundation. She holds a bachelor’s degree in biology from the University of Virginia, a master of science degree in resource management and environmental studies from the University of British Columbia, and a J.D. and LL.M. in Asian and comparative law from the University of Washington, where she served as Development Director for the Pacific Rim Law and Policy Review. While completing her LL.M., she spent a year in China studying Chinese on a Blakemore-Freeman fellowship and researching the development of water rights law in China.

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About the Contributors Jill D. Cantway is an attorney with Bjork Lindley Little PC, a Denver, Colorado, law firm where, since 2005, she has specialized in oil and gas title law, oil and gas conveyances, and other property matters. She is a member of the Bar in Colorado and Wyoming and holds a Bachelor of Arts in International Relations from Colgate University. She received her J.D., cum laude, along with a Certificate in Environmental and Natural Resources Law, from Lewis & Clark Law School in Portland, Oregon, where she was also a member of the editorial board of Environmental Law.

Christopher Denton practices oil and gas law in upstate New York with extensive experience in New York State’s Compulsory Integration law. He is the co-creator of the Atlantic States Legal Foundation. As the co-founder of the landowner coalition movement in upstate New York, he represents over 5000 families who own over 250,000 acres of land. He was the first attorney in New York State to employ an interdisciplinary approach when representing landowners by teaming with a geologist, a pipeline specialist, an environmental scientist, a CPA, and a field operations specialist. He has given seminars and lectures on oil and gas leasing around New York State since 1999 to educate landowners and farmers about the benefits and pitfalls of leasing mineral rights. He also

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teaches New York CLE courses concerning pipeline rights of way and oil and gas leasing in New York State, and serves as an adjunct instructor of oil and gas law at Elmira College. He earned his B.A. from Dartmouth College in 1972, and his J.D., with honors, from Syracuse College of Law in 1977. R. Kinnan Golemon is the founder and President of KG Strategies, LLC, in Austin, Texas. He has provided professional advice, counsel, strategic planning, and public advocacy on complex environmental, energy, and natural resources issues for more than 45 years, including 15 years of service as General Counsel for the Texas Chemical Council. He represents the largest shale oil and gas producer in the Barnett Shale Play, Devon Energy, and Shell Oil Company, another significant shale oil and gas producer. He has held numerous leadership positions in the American Bar Association Section of Environment, Energy, and Resources Law (SEER), including Section Chair 1994–95. He was a SEER delegate to the ABA House of Delegates from 2000 to 2009 and the SEER representative to the ABA Board of Governors from 2009 to 2012. He was inducted as an Initial Fellow in American College of Environmental Lawyers (ACOEL) in 2008. He serves on the Advisory Board of the Center for Global Energy, International Arbitration and Environment at the University of Texas School of Law and also as a member of Constellation’s Public Sector Energy Advisory Board. He earned a B.S. in Industrial Management Engineering from the University of Oklahoma in 1961 and an LL.B. from the University of Texas School of Law in 1967.

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Benjamin E. Griffith is a partner in the Cleveland, Mississippi, firm of Griffith & Griffith. He earned a B.A. in English and German from the University of Mississippi in 1973 and his J.D. in 1975 from the University of Mississippi School of Law. His practice concentrates on federal and state civil litigation, voting rights and election law, public sector insurance coverage, and environmental law. He is a Section Delegate to the ABA House of Delegates, Chair of the ABA Standing Committee on Election Law, and Chair of the International Steering Committee of the International Municipal Lawyers Association. He served as Chair of ABA Section of State & Local Government Law, World Jurist Association’s National President for the United States, President of the National Association of County Civil Attorneys, and Chair of the Government Law Section of Mississippi Bar. He has contributed chapters to numerous publications in his field of practice, and was recognized by his peers for inclusion in Best Lawyers In America® from 2007 through 2013 in the field of Municipal Law and in MidSouth Super Lawyers® from 2007 through 2013 in Government/Municipalities. Charles C. Grubb recently retired as Parish Attorney for Caddo Parish, Louisiana, where he served from 2002 until August 2013. Caddo Parish includes the largest urban area impacted by the Haynesville Shale, one of the world’s most prolific sources of natural gas. During his tenure as Parish Attorney, the parish was proactive in crafting regulations enabling the developers of the Haynesville Shale and private citizens to co-exist peacefully. He served as City Attorney for Shreveport,

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Louisiana, from 1978 through 1982 and again from 1986 until 1990. He currently maintains a law practice limited to state and local government law in Shreveport. A graduate of Tulane Law School (1971), he earned a B.S. degree in government from Centenary College of Louisiana. He has served as President of both the Louisiana City Attorneys Association and Louisiana Parish Attorneys Association. In 2010, he received the International Municipal Lawyers Association’s Joseph I. Mulligan, Jr., Distinguished Public Service Award. Suedeen Kelly is a partner with Akin Gump Strauss Hauer & Feld, where she co-chairs the Energy Regulatory, Enforcement and Markets Practice. She is an internationally recognized energy industry expert and two-term Commissioner with the Federal Energy Regulatory Commission (FERC). Ms. Kelly’s knowledge of the national electricity and natural gas industries includes significant experience in infrastructure development and operation, market structures, and financial products. In addition to her time at FERC, Ms. Kelly served as regulatory counsel for the California Independent System Operator; as a law professor at the University of New Mexico School of Law; as legislative aide to Sen. Jeff Bingaman (D-NM), when he was the ranking member of the Senate Energy & Natural Resources Committee; and as chairwoman and commissioner for the New Mexico Public Service Commission. She has worked in the private practice of law in New Mexico and Washington, D.C., law firms, and as an attorney for the Natural Resources Defense Council. She earned a B.A., with distinction, from the University 39

of Rochester in 1973 and a J.D., cum laude, from Cornell Law School in 1976. Chad J. Lee is an attorney with Balcomb & Green, P.C., in Glenwood Springs, Colorado, where, since 2008, he has specialized in oil and gas, business, water, and real estate matters. From 2005 to 2008 he practiced law with another Colorado firm. He holds a B.S. in Wildlife Biology from the University of Nebraska and received his J.D., cum laude, from Lewis & Clark Law School in Portland, Oregon. While at Lewis & Clark, Chad was a member of the editorial board of Environmental Law. He is licensed to practice in Colorado and Wyoming. Richard A. Liroff is founder and Executive Director of the Investor Environmental Health Network, a group of investment advisors and managers working to reduce the “toxic footprint” of businesses—their production and use of toxic chemicals. With Green Century Capital Management in Boston, Massachusetts, he leads investor efforts to promote increased disclosure by energy companies so as to reduce the environmental and business risks of hydraulic fracturing operations for unconventional reserves. He is principal author of Extracting the Facts: An Investor Guide to Disclosing Risks from Hydraulic Fracturing Operations. It identifies 12 core management goals, practices to implement them, and indicators for reporting progress. It provides guidance for equity analysts and private equity firms for evaluating/ benchmarking company management. It also provides companies with a framework for benchmarking themselves. He is author/editor of half a dozen books and numerous articles, reports, and blogs on environmental 40

policy, corporate social responsibility, and sustainability. He holds a Ph.D. in Political Science from Northwestern University and a B.A. in Politics from Brandeis University. Sorell E. Negro is a lawyer with Robinson & Cole LLP in Hartford, Connecticut, and focuses on land use, real estate, and environmental law. She earned her J.D. from Cornell Law School, where she served on the law review, and her B.S. from Georgetown University. She is active in the American Planning Association, Connecticut Bar Association, and ABA. She was one of six young lawyers selected nationally to be a fellow of the ABA’s Section of Real Property, Trust and Estate Law for 2012–14. She is a vice-chair of the ABA’s Water Resources Committee and the liaison between the ABA’s Section of State and Local Government Law and the Young Lawyers Division. She regularly writes and presents on issues related to land use, energy, and natural resources, including regulation of shale development, and is co-editing a book on urban agriculture. She received the 2013 Jefferson B. Fordham Up & Comers Award and is a 2013 Rising Star on Connecticut’s Super Lawyers® list for land use and zoning. Vera Callahan Neinast is Senior Counsel with Akin Gump Strauss Hauer & Feld in Austin, Texas. She has represented a broad range of industry participants before the Federal Energy Regulatory Commission (FERC), including interstate and intrastate natural gas pipelines; oil pipelines; midstream companies (gatherers and processors); gas storage companies; and pipeline customers, including producers, marketers, and end users. 41

She has extensive experience in administrative litigation, including initial case strategy, preparation of applications and testimony, discovery, and settlement negotiations. She has represented interstate pipelines and marketers in natural gas import and export proceedings before the U.S. Department of Energy; has broad experience before the Texas Railroad Commission on intrastate pipeline rateand service-related issues; and has represented LNG terminal developers. Before joining Akin Gump, she spent 12 years practicing energy regulatory law in another law firm, where she was a shareholder, in Washington, D.C. Her previous legal experience includes two years as a staff attorney at FERC in Washington, D.C., and two years as a law clerk for the U.S. Tax Court. She received her B.A. in English, summa cum laude, from Wright State University in 1977 and her J.D. from the Ohio State College of Law in 1980. She is admitted in Texas and the District of Columbia. Kevin Patrick is a shareholder at WATERLAW-Patrick, Miller, Kropf, Noto. The firm confines its practice to water rights, water transfers, water and waste water planning and development, basin mediation, and tribal water. He holds a J.D. from the University of Tulsa School of Law, National Energy Law & Policy Institute, and a B.A. from Virginia Tech. He is licensed in Colorado, Oklahoma, and Texas, as well as a number of U.S. District Courts, the 10th Circuit Court of Appeals, and the U.S. Supreme Court. He is a member of the Board of Visitors of the Sustainable Energy Resources Law Institute of the University of Tulsa and the Board of Advisors of the Bloomberg Water Law & Policy Monitor. 42

He has been qualified as an expert witness on water law, and is a frequent speaker, at conferences on water planning- and water rights-related topics, throughout the United States, Latin America, South America, and Europe. Jacque Rose is a paralegal who has specialized in civil litigation in Michigan for 27 years. She first became interested in fracking-related issues, especially in connection with potential threats to water resources, when land-leasing agents arrived in the tri-county area of the AuGres-Rifle Watershed in Northeast Michigan, where she resides. She co-founded the Friends of the AuGresRifle Watershed, a volunteer group dedicated to educating the public and government officials responsibly about the potential risks associated with deep-shale, high-volume hydraulic fracturing. The group gives presentations, holds public meeting forums, and provides research materials and information to other groups, throughout Michigan, concerned with fracking issues. Laurie Stern is an attorney with Lubing & Corrigan, LLC, in Jackson, Wyoming. After completing internships with the Western Environmental Law Center and the Department of Justice, she earned her J.D., cum laude, and a Masters of Environmental Law & Policy from Vermont Law School in 2011. Upon graduation, she worked as a water rights attorney for Patrick, Miller, Kropf & Noto in Aspen, Colorado. Having grown up in the water-abundant northeast, working on Colorado’s west slope gave her new insight into the complex and rapidly changing set of factors that shape and influence western water law. Laurie has written for the Western 43

Water Law & Policy Reporter and various water symposia, and maintains a particular interest in the evolution of water law and policy in the face of increased demand for limited water resources. Heather M. Urwiller is a nationally certified planner (AICP) with nine years of local government planning experience in Florida, Massachusetts, and New York, including service as Town Planner for the Town of Princetown, New York; former Planning Director for the Town of Randolph, Massachusetts; and Senior Planner for Citrus County, Florida. She is a 2001 graduate of Clarion University of Pennsylvania, with a B.A. in Anthropology. She is currently completing dual master’s degrees in the Department of Geography and Planning at the University at Albany (SUNY): a Master in Regional Planning, concentrating in environmental and land-use planning, and an M.A. in geography, concentrating in geographic information systems. A former Citrus County representative to the Suncoast section of the Florida Chapter of the American Planning Association (APA), she currently is the University at Albany Graduate Planning Students Association representative to the APA Upstate New York Chapter. Kenneth J. Warren is a founding partner of Warren Glass LLP, a firm concentrating in the fields of environmental and water resources law. He has been representing businesses in environmental regulatory, transactional, and litigation matters for more than 30 years. He also serves as outside general counsel to the Delaware River Basin Commission, a federal interstate agency managing the water resources of the Delaware 44

River Basin. He is a member of the American College of Environmental Lawyers. He served as chair of the American Bar Association Section of Environment, Energy, and Resources (SEER) in 2003–04 during which he led the Section’s 10,000 lawyers. He participated as an industry stakeholder representative on EPA’s National Environmental Justice Advisory Council from 2000 to 2006. He received his B.A., magna cum laude, from Brown University in 1975 and his J.D., magna cum laude, from the University of Pennsylvania School of Law in 1979, where he served on the law review. Terrence S. Welch, who began his legal career in 1981 in the Dallas City Attorney’s Office, is one of the founding partners of Brown & Hofmeister, LLP. He received his B.A. from the University of Illinois at Urbana-Champaign in 1976, his law degree in 1979 from the University of Houston College of Law, and an M.P.A. in 1981 from the Lyndon Baines Johnson School of Public Affairs at The University of Texas at Austin. He represents and advises local governments on a variety of issues, including land use and natural gas drilling. Since 1991, he has served as the Town Attorney for the Town of Flower Mound, Texas, and he also represents other growing communities in North Texas. He served as the 2004–05 Chair of the State and Local Government Law Section of the American Bar Association and is Immediate Past Section Chair of the State and Local Government Relations Section of the Federal Bar Association. He has published articles in law reviews and the Zoning and Planning Law Report and has presented more than 200 papers to

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professional organizations including the ABA, the APA, and municipal attorney organizations in Texas. Lisa Wozniak serves as the Executive Director for the Michigan League of Conservation Voters (Michigan LCV), headquartered in Ann Arbor, Michigan; her career spans over two decades of environmental and conservation advocacy in the political arena. She is a three-time graduate of the University of Michigan, with a bachelor’s degree and two ensuing master’s degrees in social work and education. From her first campaign experience in 1994, through her work across the Midwest for the League of Conservation Voters, to the founding of the Michigan LCV in 1999, Wozniak is a nationally recognized expert in non-profit growth and management and a leader in Great Lakes protections. Adam J. Yagelski is a land use planner and land surveyor. He holds a master’s degree in urban and regional planning from the University at Albany, State University of New York, where he received the AICP Outstanding Planning Student Award. As a planning student, he was honored by the Association of Collegiate Schools of Planning with the Ed McClure Award for Best Masters Student Paper, and he presented his work at the Finger Lakes Institute Marcellus Shale conference in 2011. Most recently he worked as associate planner with the Schoharie County, New York–based planning firm Community Planning and Environmental Associates, assisting rural communities and small towns across upstate New York with all aspects of comprehensive, farmland protection, and disaster recovery planning processes. He earned his B.A. in 46

government summa cum laude from St. Lawrence University. Drew YoungDyke is currently the Grassroots Manager at Michigan United Conservation Clubs, where he manages the citizen advocacy program, organizes volunteer fish and wildlife habitat improvement projects in coordination with the Michigan Department of Natural Resources, and writes the “On the Ground” column for Michigan Out-ofDoors Magazine. He is a graduate of Michigan State University College of Law, where his article on Asian carp litigation was published by the Animal Legal and Historical Center. As the recent Policy & Communications Specialist for the Michigan League of Conservation Voters, he coordinated the “Green Gavels” accountability project with the University of Michigan Law School, which analyzed Michigan Supreme Court environmental rulings. He is a member of the Environmental Law section of the State Bar Association of Michigan.

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Preface This book was designed to meet a need, nationwide, for information about unconventional hydrocarbon development that lawyers, public officials, planners, and citizens can use as a reference and starting point for further research. It grew out of a number of conferences, beginning with Proactive Approaches to Mitigating Impacts of Marcellus Shale Development, at the Finger Lakes Institute, Hobart and William Smith Colleges, Geneva, New York, in July 2011, where speakers offered perspectives on the rapid development of unconventional shale gas around the United States, and particularly in areas in the Northeast where this technology had not previously been applied. This conference was followed by in-person and online presentations hosted by the ABA and the American Planning Association. The ABA’s Section of State and Local Government Law presented two CLE sessions, When Fracking Comes to a Community Near You: An Ounce of Land Use Planning Is Worth a Pound of Cure, in New Orleans, Louisiana, in February 2012; and Beyond the Fracking Wars, in Dallas, Texas, in February 2013. Three ABA Sections—Energy, Environment, and Resources; Public Contract Law; and Public Utility, Communications, and Transportation Law—hosted a CLE webinar, The Natural Gas Boom: What Lawyers Should Know, in May 2012. And the APA presented three continuing education programs and webinars: Marcellus

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Shale Development: Planning for Environmental, Community and Economic Impacts in New York City in October 2012; Planning for Shale Development: Booms, Busts and Beyond, also in October 2012; and Fracking and Resource Extraction and Community Planning, in February 2013. A significant number of our authors were panelists, and we solicited their views. We seek to expand on the perspectives offered in these presentations while focusing on issues of primary concern to state and municipal governments. With respect to terminology, the “fracking wars” of the title was chosen to address several angles of the controversy around unconventional hydrocarbon exploration and development. It represents the polarized debate that has developed between those in favor of this development and those opposed to or highly skeptical of it—irrespective of whether or not high-volume, long-lateral slick water hydraulic fracturing (“frac … ing,” “fracing,” “fraccing” or “fracking”) or some other technique, such as acidizing, is the completion process of choice. Within the oil and gas industry, “frac … ing” has long been used as shorthand for the actual completion process of fracturing a geological formation, most often using high volumes of water, mixed with silica and chemicals, and pumped at high pressure into perforated pipe run through the target rock layer; however, a number of other techniques may be employed depending on the type of formation in which the hydrocarbons are found. Hydraulic fracturing has long been used to enhance recovery of hydrocarbons in vertical wells, and has also been used to 49

enhance production from water wells. In the case of oil and gas wells, technologies substituting liquefied propane, liquid nitrogen, or cold compressed natural gas (which is pressurized, but not cooled to the extent of liquefied natural gas) for water have recently been introduced. Recently, in the media and among opponents of the technology as applied, “fracking” has become shorthand for the entire process of unconventional hydrocarbon exploration and development, from site selection to final capping of the well, which may cover a period of forty years, and may impact community dynamics, land use and traffic patterns, and air and water quality, among other things. Throughout the book, as editors we have attempted to use the term “fracturing” to refer to the technical process, unless there is a direct quote; and to use the term “unconventional shale (and/or oil and/or hydrocarbon) development” to refer to the long-term lifecycle impacts of resource development, which give rise to the issues that are the main focus of this book. These impacts—both positive and negative—have fueled debate in many states over the last decade. However, with the onset of large-scale development of the Marcellus Shale, many of them became the subject of a national discourse for the first time. Starting in 2009, when the New York Department of Environmental Conservation (DEC) first issued its draft Supplemental Generic Environmental Impact Statement (dSGEIS) for Oil, Gas, and Solution Mining, we found ourselves in the midst of a public discourse that could aptly be described 50

as “fracking wars,” a polarized and often acrimonious debate where partisans appeared to choose their facts—totally “pro” or totally “con”—and argue past one another in public, in private, in the media, in signs on front lawns and by the roadside, in legislative hearings, in supermarket parking lots, and frequently, unfortunately, ad hominem. The reality is likely somewhere between two extremes: rosy visions of economic benefit and national energy independence without any health or environmental impacts on the one hand, versus the dark specter of total environmental and public health disasters on the other. As lawyers and professors, we were concerned. Many of our colleagues in the public sector, the nonprofit sector, the private bar, and the land use planning community were being asked to take positions on the issue of unconventional hydrocarbon development, primarily through hydraulic fracturing, and were grappling with conflicting sources of rapidly changing information. While unconventional oil and gas development is an industrial activity with a potentially large footprint, and as such has the capacity to have significant environmental, health, and social consequences, the equation has more than one variable. The questions of “how,” “when,” “where,” “by whom,” “using what technology,” and “under what regulatory supervision and public scrutiny does this development takes place” all have the power to influence the extent to which the positives of this development outweigh the negatives, or vice versa. The existence—or lack thereof—of sound scientific data and the ability of industry and regulators alike to incorporate 51

scientific knowledge into their practices may also have profound consequences for the impact of shale gas and oil development on the economy, environment, and community character. Beyond the Fracking Wars as a whole does not take a “pro-” or “anti-” position. It provides case studies pulled from various parts of the United States where unconventional oil and gas development is occurring. (As illustrated on the inside cover of this book, shale plays—productive or prospective—underlie large areas of the United States.) Additional case studies provide an international perspective on the impact this technology will likely have on relationships among nation states. Beyond the Fracking Wars offers a window into the basics of the technology, regulatory framework, and potential hurdles and pitfalls of unconventional oil and gas exploration and development that will be useful to a reader unfamiliar with the topic. It then discusses these topics in detail. Finally, the chapter endnotes enable a reader to pursue further information and education on any of the subjects presented. Our goal is to create an accessible and credible reference useful to seasoned legal practitioners, land owners, public officials, land use planners, and concerned citizens—and even managers and engineers in the oil and gas industry. Unconventional oil and gas exploration and development is here. Many, if not most, of the authors point out in great detail the potential drawbacks of being unprepared for these activities. But all of them offer extensive coverage of the approaches that state and local 52

governments have used in various situations, often in collaboration with industry, to mitigate or avoid the negative aspects of rapid development of this resource. The case studies in this volume offer particularly important insights, given that the lion’s share of regulation of impacts of oil and gas development is within the purview of state and local governments. The book is organized into four parts. Part 1 provides a detailed yet accessible overview of the technology of shale oil and gas development over the life cycle of a well and the multifaceted structure of the industry engaged in this exploration and development in the United States, and its relationships with regulators, including a discussion of best practices. Part 2 provides the legal foundations of the oil and gas lease and the impact of forced pooling statutes, the federal regime governing pipeline infrastructure, and local approaches to mitigate inevitable impacts on road infrastructure. In addition, this part provides coverage of the federal and state legal frameworks applicable to impacts that can be more readily classified as “environmental,” such as air pollution, water sourcing, and water pollution. Part 3 offers a series of case studies, documenting real challenges faced by municipalities where unconventional shale gas development is occurring. The combination should provide the reader with a basic understanding of the regulatory backdrop and a view of how real people in real places have navigated the challenges that this type of intensive industrial development brings. 53

Part 4 focuses on some of the less frequently addressed issues in this debate: those of long-range planning, stakeholder participation, shareholder involvement, and the need for international standards. These chapters challenge the reader to think more broadly and deeply about the implications of the current legal relationships and common practices that govern the oil and gas industry. Beyond the Fracking Wars is not exhaustive. In fact, due to the rapidly changing technology and regulatory environment, it is not possible to keep up with the current status of the many applicable statutes and regulations across the United States. Rather, our intention is for this book to serve as a useful resource on common issues associated with unconventional oil and gas exploration and development, and to open up progressive topics of discussion for all stakeholders dealing with the high level of uncertainty associated with the intensive development of this resource.

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Acknowledgments Our first acknowledgment is to one another, as editors. This book is the product of a remarkable collaboration, with mutual respect and trust, writing and editing so seamlessly that it is hard to recognize who wrote which words. We thank our authors, who provided original material and took part in multiple revisions; our peer reviewers; Hannah Jacobs Wiseman, Bruce Kramer, and Mark Lapping, who read the entire manuscript; Darrin Magee, Kinnan Golemon, and “Thyag” Thyagarajan, who read and critiqued specific chapters; and Scott Anderson, Mark Boling, and Rene Ruiz, for their assistance in shaping the book. We particularly appreciate the assistance of Adam Yagelski for additional research and editorial assistance on multiple chapters. We also thank all of the panelists of the various conferences and webinars listed in the Preface, many of whom became chapter authors and all of whom influenced our thinking. Each of us thanks our respective academic institutions and departments: the Department of Geography and Planning and the College of Arts and Sciences at the University at Albany (SUNY); and the Department of Environmental Studies and the Finger Lakes Institute at Hobart and William Smith Colleges. We thank our students, from whom we continually learn. At the American Bar Association, we thank our superb editor, Leslie Keros; the members of the Publications

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Oversight Board of the Section of State and Local Government Law, especially Martha Chumbler, Chair, and David Callies, our liaison; Richard Paszkiet, who originally suggested this book; and Tamara EdmondsAskew and Marsha Boone, who are the professional backbone of the Section. And of course we thank our families, for their love and support, and powerful intellectual curiosity. E.L.P. and B.E.K.

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PART 1 Technology and Industry Overview

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1 The Technology of Oil and Gas Shale Development Beth E. Kinne

This chapter provides an overview of many steps in the development of unconventional oil and gas resources from shale via hydraulic fracturing.1 It is designed to walk the reader through a series of commonly occurring events. These include the identification of a promising drilling location to the negotiation of the lease(s) with landowners; pad site preparation; placement of the drilling rig, ancillary equipment, and temporary structures; drilling; movement of sand, water, and chemicals; well completion (including hydraulic fracturing); pipeline installation; capture and separation of gas and other hydrocarbons; periodic reworking of the well; and reclamation of the pad site. It does not address other unconventional methods of harvesting hydrocarbons, such as acidizing of tight formations or harvesting coalbed methane or methane hydrates, nor does it cover all of the legal requirements or technical considerations involved with hydrocarbon development via hydraulic fracturing. However, by providing the reader with an overarching understanding of key processes and key terms involved in unconventional oil and gas development 58

using hydraulic fracturing, we hope to enhance the utility of the other chapters in the book. Unconventional oil and gas development targets hydrocarbons not accessible through traditional technologies. As with “conventional” hydrocarbon sources, silt, mud, and organic material laid down millennia ago were converted by pressure, heat, and time to the hydrocarbons that make up gas and oil and the geologic strata that contain them. In conventional drilling, the oil or gas has pooled in pockets within sand formations or between layers of rock. Hydraulic fracturing has been employed for decades as part of the completion stage of vertical wells (described below) in these formations to enhance the hydrocarbon recovery. However, in “tight” formations, (e.g., shale and sandstone), effective hydraulic fracturing (or other means of well completion, such as acidizing) becomes essential to produce oil or gas. Employment of this technology enables hydrocarbons to be released from lowpermeability, dense formations and to flow to an area of low pressure (i.e., the wellbore) for capture and recovery. In many of the tight oil and gas shales in the United States, the rock formations have natural vertical fractures. These natural vertical fractures led industry and government geologists to correctly suspect that further fractures could be induced in the rock to release the hydrocarbons sequestered there.2 IDENTIFYING AND MAPPING THE TARGET FORMATION

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Many places have multiple layers of potentially profitable rock, such as shales, limestones, and sandstones, containing varying concentrations of valuable 3 hydrocarbons. For example, in the eastern United States, the Marcellus Shale is currently being developed at a rapid pace, mainly for natural gas and natural gas liquids (NGLs). However, below the Marcellus Shale is the much older Utica Shale, which is proving in Ohio to be a source of oil. Deeper still are the Orinsky Sandstone4 and the Trenton Black River Limestone formations, layers that have been a target for conventional gas development in southwestern New York for decades.5 Other states with shale gas and oil reserves have similar histories, although the formations have different names and origins. The amount of hydrocarbons recoverable over the life of any well varies with type of formation (e.g., shale, coalbed methane, and tight sands), and from formation to formation (e.g., Marcellus Shale versus Barnett Shale). Moreover, the U.S. Geological Survey (USGS) reports that the total expected production of wells in the same formation may differ by up to two orders of magnitude.6 The oil and gas industry uses seismic testing to map underground rock layers, and then drills test wells to confirm the presence of a productive layer and delineate the boundaries of the target formation. Seismic testing may be conducted from public roadways or on private land. In the latter case, the testing company usually executes a written agreement with the landowner that defines the scope of the testing. Seismic mapping involves sending a vibration into the earth from a large, specially equipped truck—often dubbed a “thumper 60

truck” and sometimes referred to by the trade name Vibroseis—and “listening for” and recording the refracted vibration waves at other places.7 Various layers of the earth refract and absorb the vibrations differently, and computer analysis of refraction data allows for construction of 3-D maps of the underground geology.8 The geophones, remote sensor recorders, and associated infrastructure remain on the ground for several weeks during the mapping process and are then removed.9 Merely locating a mineral resource does not give the oil and gas company the right to produce it. Under common law, a real property owner owns his land “to the center of the earth,” unless he has relinquished rights to some portion of it.10 However, it is possible to sever mineral rights from rights in the surface property. Particularly in regions of the country with a long history of extraction of oil, gas, or coal from at least one formation, many mineral rights were long ago severed from the surface estate and conveyed in separate deeds. The industry subcontracts “landmen” to search the public records and identify the owners of mineral interests their companies hope to acquire. The landmen then set out to negotiate with the owners for the purchase, or more commonly, the lease, of the rights to those interests. Chapter 3 explains in more detail the legal norms involved in acquiring rights to develop oil and gas resources. SUPPORTING INFRASTRUCTURE: PAD SITES, ROADS, PROCESSING PLANTS, PIPELINES, AND STORAGE

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Acquisition of mineral rights generally conveys to the lessee an implied easement to use the surface estate for the many “upstream production activities” necessary to bring the gas to the surface, including locating and constructing a pad site.11 However, state law12 or the terms of a surface use agreement may limit or preclude access to the surface estate under certain circumstances. The pad site must be large enough to accommodate numerous tanker trucks and store a variety of equipment and chemicals used during production operations. Access roads are typically constructed to the pad, which may also be connected to water supply pipelines in areas where pipelines have been constructed. Once the gas flows to the surface, it must be collected and transported to the point of sale. To varying degrees, it may also be further processed or refined before it is sold. These “post-production activities” can include a mix of gathering, dehydrating, processing, and compressing the gas once it is produced.13 The associated infrastructure, such as compressor stations and gathering lines, may occupy additional space on the lessor’s property and are often the subject of agreements outside of the original lease. The construction and operation of the well and other infrastructure associated with these production and post-production activities can subject landowners and their neighbors to noise, lights, viewscape impacts, and truck traffic inherent in the construction and operation of the pad site, wells, and pipelines that transport the hydrocarbons to market. This can cause significant conflict between drillers, landowners, and neighbors. Pad Sites 62

Pad sites can vary in size depending on the number of wells to be drilled from a given location, but are commonly two to five acres. A 2013 study by Resources for the Future, which analyzed regulation in thirty-one states that have existing or potential for shale gas development, found that 65 percent of those states imposed setback requirements.14 There is high variability in setback requirements among these states. Some examples include the separation of wells, supporting infrastructure, or both from buildings in general; certain types of buildings, such as schools or residences; public roadways; places where people are known to congregate; and from certain water resources.15 In some cases, the setback is a default around which the parties are free to contract.16 In addition, some municipalities impose their own restrictions on pad site or well locations. The area for the pad site is first cleared of vegetation and topsoil, leveled, and often lined with an impervious material, which is intended to prevent migration of any chemical or water spills onto the surrounding property. In some states, the entire pad site must be lined with an impervious liner and surrounded by a berm to help contain any potential spills. Liner accidents, such as tears or seams giving way, are difficult to prevent and can result in contamination of surrounding soils or water sources. On or adjacent to the pad site there may be various pits for fresh water, drilling cuttings, drilling muds, and flowback water. In areas where multiple pad sites are in close proximity, state law may allow the use of centralized freshwater or flowback pits.17 The pad site 63

also needs to provide room for multiple tanker trucks. Some may hold fresh water and some may be pump trucks containing fluids used in fracturing the well. Others may collect and transport flowback water to a treatment or recycling center or for disposal. State regulations usually require that pad sites be reclaimed to a fraction of their original size after the completion of drilling. Topsoil must be replaced, and any compacted soil must be decompacted before being reseeded.18 In some states, flowback pits may be dewatered and the resultant salts or sludge wrapped up in the impervious pad liner and buried on site.19 After reclamation, certain minimal infrastructure remains on the now smaller pad site, including the well head and containment vessels for produced water. Roads Trucks bring in fresh water, chemicals, pipe, equipment and other supplies. They also remove flowback and produced water and equipment. Drilling a horizontal well can take between 65,000 and 600,000 gallons of water, much of which is incorporated into the drilling muds. An additional four to five million gallons of water is needed to fracture a typical horizontal well.20 Transporting five million gallons of water and the necessary chemicals, pipe, and other supplies by truck requires approximately 1,800 loaded (one-way) heavy truck trips and about 800 loaded (one-way) light truck trips per well.21 Depending on the formation and the site, one pad site can have up to eight wells (although some may have as many as sixteen). Re-fracturing of the wells after the initial decline in

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production requires additional water, chemicals, and the associated truck trips. Access roads, which are usually made of gravel or chip and seal, are often constructed across private property to access the pad site. Proper maintenance is necessary to ensure that erosion from these roads is not problematic. Impact on local secondary roads is also significant. Municipal governments need to plan for and/or require the industry to pay for the replacement and maintenance of local roads. A related issue is the challenge of maintaining road safety in the face of increased traffic combined with road surface deterioration. As detailed in chapter 11, which covers municipal navigation of the boom-and-bust cycle of gas development, and chapter 6 on road agreements, bonding, and enforcement, municipalities can employ multiple strategies to ensure they are not left without the funding necessary to repair and replace damaged public infrastructure. DRILLING AND CASING THE WELL The drilling rig is a temporary fixture at the well site. The floor of the drilling rig usually is at an elevation of somewhere between 25 to 45 feet above the pad surface. The rig mast, mounted atop the rig floor, may extend upward as much as 140 feet. The newer onshore drilling rigs also use a box-on-box design that allows the entire rig to “walk” in multiple directions in order to drill from multiple locations at the pad site without rigging down. Thus, the rig may be at a pad site for weeks or months, depending on how quickly drilling progresses and the 65

number of wells to be drilled. At Benbrook, Texas, for instance, Devon Energy has a single site that contains thirty-four completed wells and a waste disposal well.22 The rig is lighted twenty-four hours a day, and during drilling, it is quite noisy. Chapter 12 provides examples of municipal noise and light ordinances to minimize the negative impacts. In drilling a well, the drill moves through the top layers of soil and rock, through the saturated aquifer layer, and down through numerous layers of rock until the target formation is reached. Specially formulated drilling muds lubricate the drill bit and minimize disruption to the aquifer and other layers the drill bit goes through. Drilling is completed in stages. The first stage creates a space for the conductor casing, the outermost string of steel casing in the well. Regulations of conductor casing vary considerably by state, but the conductor casing is generally between 16 and 20 inches in diameter and extends from the surface of the ground to between 30 and 75 feet below the surface.23 The conductor casing protects the well from caving in and reduces the risk of contamination of aquifers from the surface.24 Inside the conductor casing is the surface casing. The surface casing normally extends from 500 to 1,500 feet below the surface.25 It must extend below the water table and is intended to protect the aquifer from any oil, gas, or other fluid contamination that might migrate along the annulus of the well. Inside the surface casing is either production casing or intermediate casing. In a well with four layers of casing (the current standard in Pennsylvania),26 intermediate casing is installed outside the production casing. The production 66

casing is the steel pipe through which the oil or gas is removed from the formation. It can run to a depth of up to 10,000 feet before turning horizontally at the “kickoff” point and running up to a mile or more through the target formation. The horizontal portion of the well allows contact with an extensive area of the formation, which is what makes unconventional oil and gas development so attractive for producing hydrocarbons. Cement is used to affix each string of casing to the surrounding rock and soil so that it is stable and will not shift. In regions of the well where one casing is inside another, cement is also used to bond the steel casing pipes to each other. The cement for the conductor and surface casings runs all the way to the surface. Improper cementing—using too little cement, or using an inappropriate mix so that curing time is not optimal—can result in the formation of channels within the cement or along the casing through which fluids or gases from the surrounding rock can migrate up the casing to the surface or to aquifers.27 For example, ineffective cementing could allow gas from a shallower, non-target layer to migrate along the outside of the casing into an overlying aquifer. Most states require cementing of the entire length of the surface casing and also require the surface casing to run below the deepest groundwater aquifer.28 In addition, many states require drillers to conduct tests to ensure proper bonding of the cement and to keep a cement bond log.29 Once a well is drilled, it may be completed (described below), or it may be shut in (temporarily capped) for completion at a future time. Factors that influence if and 67

when wells are drilled and completed include market price of natural gas and the availability of completion equipment in the region. As an example of the elasticity of demand for natural gas, rates of drilling and completion of wells in the Marcellus Shale in eastern Pennsylvania slowed in 2012, as drilling equipment, which is expensive and in limited supply, moved to the western part of the state and to Ohio, where Utica formation wells are producing mixes of hydrocarbons that are more valuable than the dry gas produced from the Marcellus formation in the eastern part of the state.30 FRACTURING THE FORMATION Once the production casing is installed, the horizontal sections of the casing are perforated in preparation for hydraulic fracturing of the target rock formation. Perforation is achieved by sending small charges into the wellbore using perforating guns. These charges create holes in the casing into the formation.31 After perforation, an acid solution may be used to clean debris out of the well.32 Then the hydraulic fracturing slurry (i.e., “gel”)—a mixture of water, sand (or other proppant, such as ceramic beads), and some other chemicals, such as friction reducers, biocides, and corrosion inhibitors—is pumped at high pressure into the well and out through the perforations, creating microscopic cracks in the formation. The proppant in the hydraulic fracturing fluid holds open the cracks, creating channels through which the hydrocarbons can flow into the wellbore. Wells are usually fractured in segments of several hundred feet at a time, starting at the farthest end of the horizontal section. Once a segment is fractured, a plug is inserted to prevent 68

premature hydrocarbon flow and the next segment is fractured. When the entire horizontal length of the well has been fractured, the plugs are drilled out so that the gas can flow back up the wellbore. While the well is being fractured, the drilling technicians monitor the pressure in the annulus of the well and the wellbore.33 Sudden changes in either of these pressures can indicate unintended results. For example, a sudden drop in pressure in the wellbore with no associated increase in pressure in the well annulus could indicate that the induced fractures have gone outside of the target formation, while a sudden increase in the pressure in the well annulus combined with loss of pressure in the wellbore can indicate loss of casing integrity.34 Using specialized equipment, some operators also monitor the growth/propagation of induced fractures. Once hydraulic fracturing is completed, the well is shut in for a time to allow redistribution of the water and gas molecules in the formation.35 MANAGING WASTEWATER Water returning from a well changes over time. “Flowback” is defined as the initial returns of water from a well during the first days or weeks after fracturing. It is similar in makeup to the fracturing fluids that went into the well. “Produced water” is defined as the later returns, which gradually flows to the surface after the well has been brought online and is simultaneously producing hydrocarbons. Produced water has been in contact with the target formation for a prolonged period of time and therefore contains high concentrations of 69

salts. In some formations, such as the Marcellus Shale, produced water may also contain naturally occurring radioactive materials (NORMS). Currently there are several approaches to managing flowback and produced water. In some states, flowback can be stored temporarily in open pits on the pad site, but eventually it must be trucked to treatment, recycling, or disposal facilities. In other states, it must be collected in tanks.36 While a portion of the flowback water can often be reused to fracture another well, eventually the residual must be disposed of either in a wastewater treatment plant equipped to handle industrial wastes, or in Class II deep injection wells.37 Deep injection disposal wells are often old oil and gas wells that are no longer productive, and they must be located in geological formations that allow for effective isolation of the waste. Pennsylvania has eight deep injection wells that are permitted to take oil and gas waste, and only five of these are active.38 New York has very few wells.39 The management of flowback and produced water waste is an area where technological advances are desirable to minimize cost of disposal and potential for spills and contamination.40 Treatment of wastewater may include simple dewatering and burial of the remaining material on site, treatment in industrial wastewater treatment plants and disposal of the solids or sludge in a landfill, or injection of the brine in a Class II deep well licensed under the Underground Injection Control program of the Clean Water Act.41 Chapter 14 provides additional details on wastewater content and recycling and disposal processes being developed from the perspective of the industry. 70

Chapter 10 discusses the importance of state regulations in mitigating impacts of unconventional oil and gas development on water resources. BRINGING A NATURAL GAS WELL ONLINE Once the formation is fractured, the pressure is released and fluids and gas flow back out of the well. After the first few days or weeks, the ratio of water to hydrocarbons coming out of the well decreases significantly. Once the percentage of water is small compared to the percentage of gas, the well can be hooked up to a sales line after final water separation at or near the pad site. Smaller amounts of water will continue to come out of the well alongside the hydrocarbons for the life of the well.42 Processing Plants Natural gas must be purified before it enters the transmission pipeline so that it does not cause problems with pipeline safety.43 Processing plants separate the various hydrocarbons that can come from the production and gathering lines from each other by removing impurities, such as water and oil; separating natural gas liquids, such as ethane, natural gasoline, propane, butane, and iso-butane; and removing non-hydrocarbon gases, such as carbon dioxide and sulfur.44 The purified streams of hydrocarbons are then routed to the appropriate transportation lines. Pipelines and Compressor Stations 71

The gas well is attached to a production line, which connects to a gathering line. Gathering lines in turn connect to larger transmission lines to carry gas long distances. Pipelines vary in diameter and operating pressure. As discussed in detail in chapter 5, the location and size of a given pipeline determines whether it comes under state or federal regulatory jurisdiction. Installation of pipelines can create disturbances to farmland, ecosystems, and habitats, and gas lines running through inhabited areas can create human safety risks if not properly operated and maintained. In addition, gas must periodically be compressed and recompressed as it moves along the network of pipelines; therefore, compressor stations are located periodically along the pipeline route. Gas must be recompressed to compensate for loss of pressure due to friction between the pipeline and the gas, new gas entering the pipeline, and gas leaving the pipeline. As gas is pressurized it heats up and requires cooling before being returned to the pipeline.45 Transmission lines, or “trunklines,” have the largest diameter and the highest pressure. At the user interface, the size and pressure of the gas lines must be stepped down again before entering municipal distribution systems and homes. Storage Storage of natural gas is important because gas use peaks during the winter months—particularly in the Midwest and Northeast—and is much lower during summer months. Therefore, provider companies often store oil and gas in depleted oil and gas reservoirs, depleted aquifers, 72

or retired salt caverns to enable guaranteed flows during the peak winter months. The Energy Information Administration provides a map of underground natural gas storage facilities in the United States on its website.46 The majority of these storage sites are exhausted oil and gas reservoirs, with a smaller percentage being depleted aquifers or salt caverns. The Federal Energy Regulatory Commission website contains records of storage facilities permitted, pending, “on the horizon,” and in the prefiling stage.47 REWORKING UNCONVENTIONAL WELLS In formations like the Marcellus Shale, gas production from horizontal wells, which initially is very high, declines significantly over time.48 It is not uncommon for the daily production volume at the first anniversary to be half of what it was during the first month the well was in production.49 Analysis of several mature shale plays indicated that this steep, linear decline profile lasts ten to fifteen months. Rates of production thereafter continue to decline, but at a shallower—though still linear—rate.50 Maintaining steady production rates from a shale play like the Marcellus, therefore, requires continued drilling of new wells or restimulation (a repeat of the hydraulic fracturing treatment) of existing wells to increase production. At the time of writing, restimulation of wells is not a common practice, and oil and gas companies primarily depend on continued drilling of new wells to maintain production volumes. RECLAMATION 73

The Bureau of Land Management, which manages the federal public land upon which many oil and gas wells have been drilled, states, “[t]he ultimate objective of reclamation is ecosystem restoration, including restoration of the natural vegetation community, hydrology, and wildlife habitats.”51 Drilling permits may limit the maximum area disturbed at any one time. This necessitates interim reclamation, which may also include revegetation and recontouring of the land. Final reclamation involves removal of almost all of the equipment, save the “Christmas tree” well head and a small condensate tank to collect the small amounts of water that will continue to be produced with the gas. In some instances a separator or compressor station may also be installed on the pad site. The pad site is usually reclaimed from the original five acres to an area of about one-half acre (although larger pad sites might not be reclaimed to such a small area). Access roads may be removed and the area under them that was compacted by thousands of truck trips tilled and reseeded to promote the return to close to normal hydrological flow and vegetation patterns. Reclamation standards are typically set by individual states and determination of reclaimed status dependent on approval by state inspectors. Industry best practices also set standards for reclamation.52 In many states where highvolume hydraulic fracturing techniques are being used, such as Pennsylvania and West Virginia, few of the horizontal wells are old enough for the pad sites to have been fully reclaimed. CONCLUSION

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For attorneys, mineral rights owners, or regulating bodies entering into or enforcing the legal relationships involved, a basic understanding of the technical processes promotes informed decision making. The steps in producing oil and gas using hydraulic fracturing technologies are manifold and complex as are the legal relationships involved. As technologies for accessing hydrocarbon resources develop further, the list of technologies qualifying as “unconventional” will also likely change. Although they are addressed here with respect to a specific set of technologies used to extract oil and gas, many of the issues addressed by the authors in this book are inherent in many types of extractive resource development, and therefore will likely continue to require creative management and evolving regulatory strategies. NOTES 1. Hydraulic fracturing is one completion method used in development of unconventional oil and gas resources such as tight sands and shales. The category “unconventional” is somewhat fluid, and is used to describe formations in which newer technologies are necessary to exploit hydrocarbons historically inaccessible via vertical drilling technology, as well as those technologies themselves (directional drilling, hydraulic fracturing, acidizing, and collection of coalbed methane, for example). For an explanation of unconventional gas resource types, see http://www.naturalgas.org/ overview/unconvent_ng_resource.asp.

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2. See, e.g., T. Engelder, G.G. Lash & R. Uzcategui, Joint Sets That Enhance Production from Middle and Upper Devonian Gas Shales of the Appalachian Basin, 93 AM. ASS’N PETROLEUM GEOLOGISTS BULL. 857 (2009). 3. For current productive formations in New York State, see, e.g., New York State Geological Survey Reservoir Characterization Group, available at http://www.nysm.nysed.gov/nysgs/research/oil-gas/ rcg.html. 4. John A. Harper, The Marcellus Shale: An Old “New” Gas Reservoir in Pennsylvania, 38 PA. GEOLOGY, no. 1, 2008 at 2. 5. For a stratigraphic diagram of the geology of southwest New York State showing the relationship among these three formations, see NY DEC, Stratigraphic Section, SW New York State, available at http://www.dec.ny.gov/energy/33893.html. 6.

R.R. CHARPENTIER & T.A. COOK, U.S. GEOLOGICAL SURV. OPEN-FILE REP. 2013–1001, VARIABILITY OF OIL AND GAS WELL PRODUCTIVITIES FOR CONTINUOUS (UNCONVENTIONAL) PETROLEUM ACCUMULATIONS (2013), available at http://pubs.usgs.gov/of/2013/1001/.

7. M. Landefeld & C. Hogan, Seismic Testing and Oil & Gas Production, Oil and Gas, Ohio State University Extension, Oil and Gas Development Fact Sheet 76

Series, available at http://serc.osu.edu/sites/drupalserc.web/files/ 2012%20seismic%20testing%20Fact%20Sheet(1).pdf. 8. U.S. Dep’t of Transp., Pipeline & Hazardous Materials Safety Admin., Technologies of Oil and Gas Exploration, http://primis.phmsa.dot.gov/comm/ Technologies.htm (last visited Sept. 20, 2013). 9. Information in this paragraph was taken from Chesapeake Energy, Seismic Exploration, available at http://www.askchesapeake.com/Barnett-Shale/NaturalGas/Pages/Seismic-Exploration.aspx. 10. There is some evidence that the further underground the rights are, the less secure ownership by the owner of the surface estate. J. Sprankling, Owning the Earth, 55 UCLA L. REV. 979 (2008). 11. George A. Bibikos & Jeffrey C. King, A Primer on Oil and Gas Law in the Marcellus Shale States, 4 TEX. J. OIL GAS & ENERGY L. 156 (2009). 12. For example, New York State’s compulsory integration law (New York Environmental Conservation Law, Title 9, Art. 23) precludes the well operator from trespassing on the property of a landowner that has been subject to compulsory integration. Land Owner Option Guide, N.Y. DEPARTMENT OF ENVIRONMENTAL CONSERVATION, http://www.dec.ny.gov/energy/ 1590.html (last visited Sept. 20, 2013).

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13. Id. 14. NATHAN RICHARDSON ET AL., RESOURCES FOR THE FUTURE, THE STATE OF STATE SHALE GAS REGULATION (June 2013), available at http://www.rff.org/rff/documents/RFF-RptStateofStateRegs_Report.pdf. 15. Id. 16. Id. 17. E.g., W.VA. CODE § 22-6A-9; PA. DEP’T OF ENVTL. PROT., form 5500-PM-OG0084 Rev. 12/ 2010, APPLICATION INSTRUCTIONS FOR A DAM PERMIT FOR A CENTRALIZED IMPOUNDMENT DAM FOR OIL AND GAS WELLS (2010), available at http://www.elibrary.dep.state.pa.us/dsweb/Get/ Document-82541/5500-PMOG0084%20Instructions.pdf; and N.Y. DEP’T OF ENVTL. CONSERVATION, PRELIMINARY REVISED DRAFT SUPPLEMENTAL GENERIC ENVIRONMENTAL IMPACT STATEMENT ON THE OIL, GAS AND SOLUTION MINING REGULATORY PROGRAM chs. 1.1.1 and 5.7.2 (2009), available at http://www.dec.ny.gov/data/dmn/ ogprdsgeisfull.pdf. 18. See N.Y. STATE DEPT. OF AGRIC. AND MKTS., GUIDELINES FOR CONSTRUCTION AND RESTORATION AT NATURAL GAS WELL DRILLING SITES IN AGRICULTURAL AREAS, 78

available at http://www.agriculture.ny.gov/AP/ agservices/Well_Pad_Guidelines.pdf; see also COLORADO OIL AND GAS CONSERVATION COMMISSION, RECLAMATION REGULATIONS, sections 1003 and 1004, available at http://cogcc.state.co.us/RR_Docs_new/rules/ 1000Series.pdf (last visited Sept. 20, 2013). 19. E.g., MICH. ADMIN. CODE r. 324.407(9). 20. Chesapeake Energy, Water Usage in Hydraulic Fracturing, HYDRAULIC FRACTURING FACTS, http://www.hydraulicfracturing.com/Water-Usage/ Pages/Information.aspx (last visited Sept. 20, 2013). For water usage data by shale play, see individual fact sheets at Water, CHESAPEAKE ENERGY, http://www.naturalgaswaterusage.com/Pages/ information.aspx (last visited Sept. 20, 2013). 21. N.Y. DEP’T OF ENVTL. CONSERVATION, REVISED DRAFT SUPPLEMENTARY GENERAL ENVIRONMENTAL IMPACT STATEMENT, at 6-603 tbl.6.60 (2011). 22. Author’s correspondence with Kinnan Golemon, Esq., Contract Governmental Affairs Representative for Devon Energy (Apr. 2013) (on file with author). 23. HARVEY CONSULTING, LLC, NEW YORK STATE CASING RECOMMENDATIONS FOR REGULATION: REPORT TO NRDC (Sept. 16, 2009), available at http://docs.nrdc.org/energy/files/ ene_10092901e.pdf. 79

24. Id. 25. See Texas Oil and Gas Industry, Oil and Gas in Texas: A Joint Association Communication from the Texas Oil and Gas Industry, OIL AND NATURAL GAS IN TEXAS, http://www.oilandnaturalgasintexas.com/flipbook/#/4 (last visited Sept. 20, 2013). 26. See 25 PA. CODE § 78.83 (2011).

27. U.S. DEP’T. OF ENERGY, STATE OIL AND NATURAL GAS REGULATIONS DESIGNED TO PROTECT WATER RESOURCES (2009), available at http://energy.wilkes.edu/PDFFiles/Library/ State%20Oil%20and%20Gas%20Regulations%20Designed%20to%20P 28. Id. 29. Id. 30. Andrew McGill, Low Gas Prices Drive Drillers West, PITTSBURGH POST-GAZETTE (July 30, 2012, 12:07 AM), http://www.post-gazette.com/stories/local/ marcellusshale/low-gas-prices-drive-drillers-west-insearch-of-profit-646802/ (includes rig count graphic based on US EIA gas price data and Baker Hughs rig count). 31. Rick von Flatern, Defining Completion: The Science of Oil and Gas Well Construction, OILFIELD REV., WINTER 2011, at 50, available at

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http://www.slb.com/resources/publications/ oilfield_review/~/media/Files/resources/ oilfield_review/ors11/win11/ defining_completion.ashx. 32. Id. 33. YCELP, Balancing Environmental, Social and Economic Impacts of Shale Gas Development Activities, VIMEO (Jan. 23, 2013), http://vimeo.com/ 58162903 (video of webinar with Mark K. Boling, Emerging Issues in Shale Gas Development Series, Yale Law School). 34. Id. 35. Terry Engelder, Fracking: A Conversation with the Public about Risk, Public Lecture at Hobart & William Smith Colleges (Dec. 7, 2012). 36. NATHAN RICHARDSON ET AL., RESOURCES FOR THE FUTURE, THE STATE OF STATE SHALE GAS REGULATION (June 2013), available at http://www.rff.org/rff/documents/RFF-RptStateofStateRegs_Report.pdf. 37. EPA, Natural Gas Extraction, Hydraulic Fracturing, http://www2.epa.gov/hydraulicfracturing#wastewater (last visited Sept. 20, 2013). 38. Susan Philips, Deep Injection Wells in Pennsylvania, STATEIMPACT (June 26, 2012, 11:52 AM),

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http://stateimpact.npr.org/pennsylvania/maps/locationof-deep-injection-wells-in-pennsylvania/. 39. OHIO DEP’T OF NATURAL RES., PRELIMINARY REPORT ON THE NORTHSTAR 1 CLASS II INJECTION WELL AND THE SEISMIC EVENTS IN THE YOUNGSTOWN, OHIO, AREA, (2012), available at http://ohiodnr.com/downloads/northstar/ UICreport.pdf. 40. According to the Produced Water Society, approaches to treatment can be categorized into removal of total suspended solids (TSS); removal of hardness (salts) and oil and grease; removal of total dissolved solids; and centralized treatment (used with water with a specified re-use or that is destined to be discharged). See Mark Kidder et al., Treatment Options for Reuse of Frac Flowback and Produced Water from Shale, WORLD OIL, July 2011, available at http://www.worldoil.com/July-2011-Treatmentoptions-for-reuse-of-frac-flowback-and-producedwater-from-shale.html. 41. Class II Wells—Oil and Gas Related Injection Wells, ENVTL. PROT. AGENCY, http://water.epa.gov/type/ groundwater/uic/class2/index.cfm (last visited Sept. 20, 2013). 42. The process described here is somewhat different from what is required to bring a crude oil or crude oil and liquids well on line.

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43. ENERGY INFO. ADMIN., NATURAL GAS PROCESSING: THE CRUCIAL LINK BETWEEN NATURAL GAS PRODUCTION AND ITS TRANSFER TO MARKET (2006), available at http://www.eia.gov/pub/oil_gas/natural_gas/ feature_articles/2006/ngprocess/ngprocess.pdf. 44. U.S. Dep’t of Transp., Pipeline & Hazardous Materials Safety Admin., Fact Sheet: Natural Gas Processing Plants, PIPELINE & HAZARDOUS MATERIALS SAFETY ADMIN., http://primis.phmsa.dot.gov/comm/factsheets/ fsnaturalgasprocessingplants.htm (last updated Dec. 1, 2011). 45. ENERGY INFO. ADMIN., NATURAL GAS COMPRESSOR STATIONS ON THE INTERSTATE PIPELINE NETWORK: DEVELOPMENTS SINCE 1996 (2007), available at http://www.eia.gov/pub/ oil_gas/natural_gas/analysis_publications/ ngcompressor/ngcompressor.pdf. 46. About U.S. Natural Gas Pipelines, Energy Info. Admin, http://www.eia.gov/pub/oil_gas/natural_gas/ analysis_publications/ngpipeline/ undrgrndstor_map.html (last visited Sept. 20, 2013). 47. Natural Gas Storage, FED. ENERGY REGULATORY COMM’N, http://www.ferc.gov/ industries/gas/indus-act/storage.asp (last updated June 10, 2013).

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48. Matt Kelso, Marcellus Shale Production Decline over Time in Pennsylvania, FRACTRACKER (Sept. 5, 2011), http://www.fractracker.org/2011/09/marcellusshale-production-decline-in-pennsylvania/. 49. Jason Baihly, et al., Study Assesses Shale Decline Rates, AM. OIL AND GAS REP., May 2011, available at http://www.slb.com/~/media/Files/dcs/ industry_articles/201105_aogr_shale_baihly.ashx. 50. Arthur E. Berman & Lynn F. Pittinger, U.S. Shale Gas: Lower Abundance, Higher Cost, THE OIL DRUM (Aug. 5, 2011, 10:15 AM), http://www.theoildrum.com/node/8212. 51. U.S. Dept. of Interior, Bureau of Land Management, Reclamation and Abandonment, BUREAU OF LAND MGMT., http://www.blm.gov/wo/st/en/prog/energy/ oil_and_gas/leasing_of_onshore/og_reclamation.html (last updated Oct. 20, 2009). 52. See Reclamation Resources Guide for Oil and Gas Development, INTERMOUNTAIN OIL AND GAS BMP PROJECT, http://www.oilandgasbmps.org/ resources/reclamation.php (last visited Sept. 20, 2013). This site includes links to reclamation regulations for Utah, New Mexico, and Wyoming.

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2 The Oil and Gas Industry Operations and Best Practices Erica Levine Powers and Adam J. Yagelski

The authors acknowledge the research assistance of Heather Urwiller, AICP. INTRODUCTION

This chapter provides an overview of the structure of the industry for oil and gas shale exploration and development in the United States. Specifically, it outlines how companies are organized during the exploration and production phase and how contractual relationships among operators and oilfield service companies are structured and how they have changed. This chapter also discusses industry best practices in anticipating and preventing accidents in high-risk technologies, including industry-proposed collaboration with stakeholders for baseline scientific research, model disclosure statutes, and regulatory oversight. Although this chapter does not address recent tort cases, it references related articles.1

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For a technical overview of the process of exploration, drilling, and bringing a well online, see chapter 1. WHAT COMPRISES THE SHALE OIL AND GAS INDUSTRY? Far from being monolithic, this industry is comprised of oil and gas companies that range from some of the largest companies in the world—both privately and publicly held—to small players active in one region of the United States. In addition to these “operators,” which are essentially companies responsible for oilfield management and day-to-day operation, there are manifold companies providing services of all types, from specialized downhole operations to logistics and trucking. Bringing such a diverse set of companies together on a given well pad necessitates establishing some key operational and contractual relationships, including agency and insurance, to address responsibility, risk, and liability. What is known as the U.S. “oil and shale gas industry” actually includes entities active in each of three sectors: upstream, midstream, and downstream. The upstream sector, also known as exploration and production (E&P), includes entities engaged in one or more of the following activities: finding, developing, or producing oil or gas. The midstream sector encompasses activities related to processing, transportation, storage, and marketing of both raw hydrocarbons and refined products. Downstream sector activities include refining and processing as well as marketing and distribution. Some companies may have investments or operations in more than one sector. The 86

figure below provides an overview of the activities necessary to bring oil and gas products from underground deposits to consumers and how the activities are structured. As this diagram indicates, there is some overlap in function among the three sectors. Operators Oil and gas companies are probably the best-known component of the E&P sector. Also known as “operators,” they decide where to drill; specify well depth, diameter, and direction; obtain drilling permits; and secure the right to access the well site.2 To access the hydrocarbon reserves, operators usually lease the mineral rights from landowners. For a more extended treatment of mineral estate and surface access and other issues involved in leasing, see chapter 3. Among operators, there is a basic distinction between “fully integrated” companies, which are active in all three sectors, and “independent producers”, which typically are active in the upstream and midstream sectors but do not have refining capacity. Fully integrated companies include the so-called oil majors, such as ExxonMobil, BP, ChevronTexaco, and Shell Oil. These companies—some of the largest in the world—are engaged in all aspects of the oil industry, from E&P to refining and marketing of refined products. Independent producers explore and/or produce crude oil and natural gas, and they may also own pipeline infrastructure or otherwise be active in the midstream sector. These include companies like Devon Energy, 87

Anadarko, Apache Corporation, Range Resources, Southwestern Energy, Chesapeake Energy, and some 8,000 other entities varying in number of employees from a handful to thousands.3

Overview of petroleum industry activities Source: Adapted from Silvana Tordo, Brandon S. Tracy & Noora Arfaa, National Oil Companies and Value Creation 2 (World Bank, Working Paper No. 218, 2011), available at http://siteresources.worldbank.org/ INTOGMC/Resources/9780821388310.pdf. Reprinted by permission of the World Bank.

Many fully integrated and independent producers also have midstream operations in the areas where they have extensive shale oil and gas E&P operations. However, these entities, including most independent producers, may also rely on some third-party midstream operators in 88

many of the shale oil and gas plays. This is particularly true in regions with new plays that lack gathering and transmission infrastructure, or where the pipeline and processing infrastructure requires upgrades to handle the increased pressures associated with unconventional wells and to carry liquids. There is not a direct correlation between the size of an operator and the number of sectors in which it operates. A common way to measure the size of operators is natural gas produced per day. In the third quarter of 2012, both fully integrated and independent companies were listed among the top 10 producers of natural gas in the United States. ExxonMobil topped this list with 3,847 MMcf/day produced and was followed by independent Chesapeake Energy with 3,095 MMcf/day. Hess Corporation, a large integrated company, ranked near the bottom with daily production of 112 MMcf.4 Private vs. Nationally Controlled Oil Companies Not all companies operating in U.S. plays of unconventional hydrocarbons are U.S. companies. In addition, it is also important to distinguish between privately held operators and those that are state-owned. To varying degrees, government-controlled national oil companies (NOC) like PDVSA, Venezuela’s state oil company, operate with state-mandated, non-market objectives, such as wealth re-distribution and jobs creation. This is in contrast to the private international oil companies (IOC), which are responsive to shareholders. A further distinction between many IOCs and NOCs is that the degree of vertical integration among NOCs is 89

typically lower, though it appears to be growing. Much like their counterparts in the private sector, some statecontrolled oil companies have refining and sales operations, which oil companies—especially IOCs—have long used to capture the value-added of downstream products, create demand security, and hedge risk in volatile, changing oil markets. Other NOCs are less integrated and have activities concentrated primarily in the upstream sector.5 In contrast, IOCs appear to be concentrating on the more profitable upstream sector. An example of this trend is a steady decrease of retail sales (e.g., gasoline at gas stations) as a percentage of total sales of U.S. refiners.6 Some large NOCs also are conducting business in the United States as operators. In some instances, they have taken positions in U.S. unconventional plays to replace declining reserves at home.7 Foreign investment in U.S. shale gas plays—whether by NOCs or other private investors—has generally increased. Since 2008, there have been at least 21 joint ventures between U.S. acreage holders or operators and foreign companies.8 For example, Statoil, which is majority-controlled by the Norwegian government, has become an active operator in several U.S. unconventional plays, including the Marcellus, Eagle Ford, and Bakken formations.9 Chinese oil companies, many of which are now stock corporations whose assets remain majority-controlled by the central government, also have a significant presence in U.S. shale plays. Since 2010, there have been several joint ventures between U.S. operators and Chinese firms. 90

These deals allow U.S. companies to access capital while Chinese and other foreign firms benefit from exposure to unconventional drilling technology. Some transactions have involved purchase of drilling rights as well. For example, Sinopec recently purchased from Chesapeake Energy rights to drill in Oklahoma, and state-owned China National Petroleum Corp. (Cnooc), China’s largest oil company, has purchased Canadian company Nexen Inc. The Cnooc-Nexen deal is instructive in terms of the degree of control U.S. regulators exercise over access to mineral resources: Cnooc was blocked from access to Nexen’s Gulf of Mexico operations in U.S. waters.10 Indeed, legislation passed in the wake of a controversial attempt by a company ultimately owned by the United Arab Emirates to acquire operating leases to six major U.S. ports led to a broadening of oversight of “major energy assets.” This has caused increased scrutiny for transactions involving U.S. energy resources.11 Oilfield Services Companies The E&P sector also includes oilfield services companies (OFS)—the “unsung workhorses”12 of the oil and gas industry. Entities providing a very wide range of services constitute OFS. While they were much smaller in the 1980s when operators performed more of their own drilling work, OFS have since grown as operators have outsourced a number of these functions. Recent growth has been driven by both higher oil and gas prices and investment in new technology (e.g., 4D seismic and directional drilling).13 91

The activities of OFS companies can be divided into at least three categories: manufacturing and supply of drilling equipment and materials; owning and leasing of drilling equipment; and carrying out tasks associated with finding and extracting oil and natural gas.14 Some analysts also include seismic and oil/gasfield analysis as a fourth category.15 Drilling companies provide equipment (e.g., a drill rig), personnel, and expertise to drill the well according to specifications provided by well operators. These entities can be large companies with global operations and many rigs, subsidiaries of the oil companies operating gas wells, or small companies with a few rigs and operations limited to one play. OFS also includes a host of companies of all sizes that provide various services, such as pipe and equipment suppliers; trucking firms; sand, chemical and drilling additive producers; general construction and excavation contractors; water and waste water hauling, treating, and disposal firms; consulting engineers, geologists, land surveyors, landmen and right-of-way agents; tubing and downhole equipment manufacturers; well testing and completion entities; drilling mud engineers; and a multitude of other enterprises. Some OFS companies that provide an array of sophisticated technologies, services, and other products to support well drilling and completion are, by some measures, larger than the oil companies they serve. For example, the market capitalization of Schlumberger, at $91 billion, exceeds that of Statoil and Conoco-Philips by over 20 percent. One thing that differentiates the largest OFS companies, such as Schlumberger, Halliburton, and 92

Baker Hughes, from operators is that OFS companies spend higher percentages of revenue on research and development.16 Putting It Together The process of drilling a well can involve a complex relationship between an operator, OFS companies, and companies involved in the midstream sector. With some exceptions, operators do not own drilling equipment but perform management and interpretive functions, such as using geophysical data provided by OFS companies to locate drilling activities.17 Typically, once the location of a well is determined, the principal contractual relationship during the drilling phase is between an operator, which has the legal right to drill in a particular place, and a drilling contractor, which supplies the drill rig and labor.18 Under this standard model, the operator is responsible for well designs and supervision of well construction activities, and the drilling contractor is responsible for implementing this design. Yet operators, as well as drilling contractors in turn, can utilize many sub-contractors to perform a range of functions.19 Thus, a number of additional OFS companies become third parties providing a variety of essential services, such as site preparation, equipment supply, logging and testing, well completion, well servicing, etc. Due in part to the intensity of drilling and completion activity involved with the development of shale hydrocarbon resources and in part to a long-term trend in which operators contract more “noncore activities” to the service sector,20 the contractual terms and requirements 93

insisted upon by many operators for OFS services have recently undergone rapid change so that the drilling and completion more resembles a continuous manufacturing setting compared to the more or less “one off” deal terms of the past.21 What is broadly changing is a move toward the packaging of services within incentive-based relationships focused on “the well” as a product and a move away from proliferating individual contracts that sometimes placed the interests of operators and OFS at odds. A good example of this is the integrated services drilling process model used by Schlumberger.22 In traditional drilling processes, operators might supervise, coordinate, and manage many discrete tasks. For instance, during well construction, tasks treated separately might include directional drilling, cementing, and testing functions—sometimes under individual contracts. Each task would be treated separately, and each contractor would have a narrowly defined scope of work. Operators, responsible largely for well design, would be required to supervise the implementation program. Under integration, defined as “the packaging of various services or products under a single contract,”23 these tasks are grouped, or “bundled,” as an integrated drilling services contract, potentially involving several OFS company product lines as well as third-party contracts. Separate integrated contracts might then be issued for other bundled services under the broader heading of “well construction.” These could include drilling rig operations (e.g., logistics and casing running) and data acquisition (e.g., geophysical data, drilling reports, and completion 94

drawings). Among the variables influencing how these relationships will play out are the size of the operator, the extent of an operator’s presence in a particular play, the specific geologic conditions, and any changes in well conditions.24 Market conditions for supply of OFS are also important. For example, a scarcity of available OFS providers, along with the dynamic changes in downhole equipment and diagnostic technologies, can mean rapid evolution of relationships between operators and suppliers. In some cases, this has resulted in the use, in long-term contracts between operators and rig contractors, of rates indexed to commodity and labor prices, thus maintaining a degree of certainty for both parties and allowing each to share in market pricing risks.25 Market conditions may also have an impact on the availability of skilled OFS providers. These in turn may be a factor in the incidence of accidents or system failures, such as blowouts or cement casing failures.26 Cross-Indemnification and Risk Apportionment In the oil and gas industry, the contractual relationships commonly governing these multiple interlocking operations are “relatively uniform in how the risks are allocated.”27 Under contracts known as “knock-forknock” indemnities, or KK indemnities, parties (e.g., operators and drilling contractors) indemnify each other for claims arising out of death or personal injury of their personnel, loss or damage to their property, and pollution emanating from their property—regardless whether any 95

negligence, breach of contract, or violation of statutory duty exists. In addition, so-called pass-through indemnification may extend these indemnities to cover members of a named party’s group—subcontractors and third parties, for example—whether named in the agreement or not. Although there may be no privity of contract between the operator, including its agents and assigns, and the landowners or mineral rights owners (“landowners”) who granted exploration and development rights to the operator, some leases now provide such indemnifications to landowners. See, for example, this model lease language from the state of Ohio: Indemnity: Lessee agrees to defend, indemnify, and hold harmless Lessor and Lessor’s heirs, successors, representatives, agents, and assigns (“Indemnitees”), from and against any and all claims, demands, and causes of action for injury (including death) or damage to persons, property and/or natural resources and fines or penalties, or environmental matters arising out of, incidental to, or resulting from the operations of or for Lessee or Lessee’s servants, agents, employees, guests, licensees, invitees, or independent contractors, and from and against all costs and expenses incurred by Indemnitees by reason of any such claim or claims, including attorneys’ fees; and each assignee of Lessee of this Lease, or an interest therein, agrees to indemnify and hold harmless Indemnitees in the same manner provided above. Such indemnity shall apply to any claim arising out of operations conducted under or pursuant to this Lease, however caused.28

Although indemnification clauses in leases are increasingly common,29 absent such provisions the

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landowners may be limited to compensation provided by tort law. The justification for widespread use of KK indemnities in the oil and gas industry rests on the following conditions: the difficulty of proving fault where complex, inherently hazardous operations are taking place; the complex structure of relationships and numerous parties involved in developing any single well; and the possibility that contractors and third parties would each require insurance for the manifold potential risks due to exposure created by these many relationships.30 Indeed, the BP Macondo well blowout in 2010 (BP Macondo incident), even though offshore, has functioned as something of a test of the use of KK indemnities in the onshore oil and gas industry. 31 Some states, notably Louisiana, Texas, New Mexico, and Wyoming have in place Oilfield Anti-Indemnity Acts that impose limitations on KK indemnities.32 Insurance industry commentators suggest that certain jurisdictions may have public policy objections to these indemnities.33 Protection of local firms is one example. The Texas and Louisiana statutes limiting indemnities appear to have been driven by some oil companies’ attempts to contractually transfer all liability to local providers of materials and services.34 Many states, including Texas and Louisiana, have statutes that limit the ability of parties to indemnify themselves against their own negligence. In fact, Texas and Louisiana take different and conflicting approaches to that problem.35

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Cross-indemnification agreements attempt to apportion risk, which is then backed by several types of insurance. Perhaps the most common form of coverage is commercial general liability (CGL), yet there are more specialized insurance products available. These are predominantly carried by operators, which assume control of a drilling site, although additional coverage might also be purchased by some large drilling contractors.36 Among these are operators extra expense (or OEE, which is also known as “control of well”) coverage, which covers blowouts, as well as coverage designed specifically to cover environmental risks, broadly called environmental impairment liability (EIL) coverage, which covers gradual release from a well site—“latent hazards,” like groundwater contamination.37 This form of coverage is used to supplement GCL policy extensions, most of which limit coverage to “abrupt and instantaneous” releases. Although unconventional operations entail new risks, EIL-type coverage is less commonly carried by onshore operators compared to GCL and OEE coverage.38 While its use is growing, only a subset—about 30 percent to 40 percent of oil and gas companies “with significant fracturing operations” currently carry it.39 There are concerns that fewer insurers will be willing to provide EIL coverage for fracking operations and that EIL coverage prices may make this coverage prohibitively expensive for operators.40 Lack of regulatory clarity and high profile announcements by insurers like Nationwide that they will not insure against fracking-related risks are part of the reason for insurers’ trepidation.41 The potential for coverage disputes are another, with some observers 98

likening the issues raised by fracking to asbestos litigation.42 The potential for widespread contamination presents a particular problem in light of how KK indemnities relate to insurance risk transfer and the incentives these contracts create to reduce pollution risk.43 Regional Diversity Underlying these and other variables influencing the nature of production activities are “the realities of regional diversity” as articulated in 2011 by the Shale Gas Production Subcommittee of the Secretary of Energy Advisory Board (Subcommittee Report),44 which highlights the fact that the nature of operations can be highly variable within and between individual plays. Much variation is attributable to differences in underlying geologic conditions. Moreover, the rapid integration of regions across the United States into the “supply mix,” particularly those areas without a recent history of drilling and production activity but now experiencing significant development pressure, has led to the evolution of drilling and completion technology, field practices, and regulation.45 BEST PRACTICES The evolution in technology and practice, the geological diversity in shale oil and gas exploration, and the increased potential for—and awareness of—environmental contamination risks posed by shale exploration and development46 have each brought new

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attention to best practices within the industry.47 The Subcommittee Report defined best practices as “industry techniques or methods that have proven over time to accomplish given tasks and objectives in a manner that most acceptably balances desired outcomes and avoids undesirable 48 consequences.” The drilling technology is rapidly evolving, so there is understandable concern49 lest a specific technology become a regulatory requirement. Best Practices and Regional Variation How closely regulations governing industry practices are tailored to local conditions and the needs of industry remains a potent issue. According to the Subcommittee Report, “A single best engineering practice cannot [be] set for all locations and for all time.”50 Local variation in regulation can be beneficial because it results in regulatory controls more responsive to region-specific variables, such as geology and history of hydrocarbon development, and is less “removed from field operations.”51 The idea that best practices can serve as a basis for environmental protection is not a new one.52 For example, a well-known analogy from the water quality arena is the National Pollutant Discharge Elimination System (NPDES) Phase II requirements, which place primacy upon decisions taken at the municipal level. The oil and gas industry also has a history of using best management practices (BMPs).53

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One recent example in the oil and gas industry is a collaboration between independent producer Southwestern Energy and the Environmental Defense Fund (EDF) to develop a set of model regulations for hydraulically fractured wells. The effort focuses on well integrity because it was found to be common to all reported cases of water well contamination linked to fracking.54 Still in draft form, this document is an outgrowth of a review of state regulatory programs as well as industry standards. It sets out standards for all phases of well construction, from well planning and permitting, to predrilling water sampling, casing and cementing, well completion and fracturing, and plugging and abandonment. The document also contains disclosure provisions.55 A related effort is the set of fifteen performance standards developed by the Center for Sustainable Shale Development (CSSD) tailored to shale gas development in the Appalachian Basin, which includes the Marcellus formation. The performance standards include the following provisions: 90 percent recycling of flowback and produced water; use of closed loop containment in place of open pits for handling of flowback; analysis of stratigraphic confinement adequacy to prevent migration of frac fluids from the target formation; implementation of a sourcewater (surface and groundwater) monitoring program; and frac fluid disclosure, among others.56 In addition, these standards will be linked to a certification process, which is currently under development.

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At the time of writing, the CSSD partnership includes operators like Shell, Chevron, and Consol Energy as well as environmental groups like EDF and the Pennsylvania Environmental Council.57 As some observers have commented, strategic collaborations like these are “lonely in the middle,” where the pressure of pro-industry groups, opposition of environmental interests, and primacy of state regulation have created a challenging and polarized environment.58 The Subcommittee Report concludes that “a more systematic commitment to a process of continuous improvement to identify and implement best practices is needed, and should be embraced by all companies in the shale gas industry.”59 This includes a public health and protection element. The Subcommittee Report states, “Many companies already demonstrate their commitment to the kind of process we describe here, but the public should be confident that this is the practice across the industry.”60 For example, FracFocus, the industrysupported disclosure mechanism increasingly required by states such as Pennsylvania, is intended to satisfy the public’s need to know what chemicals are used locally in frac fluids. Beyond Best Practices The specification of best practices is not a guarantee that oil and gas operations will always be safer from an environmental or a health perspective.61 Organizational theorists dealing with socio-technical systems that involve high-risk technologies and high catastrophic potential have recognized that certain features of these systems, 102

including deepwater drilling, are inherently risky and that accidents can be considered “normal.” That is, a degree of unpredictability, complexity, and tight coupling of system elements makes accidents intrinsically likely—even under proper management and even after careful design.62 This may be applicable to mineral resource recovery technologies, such as hydraulic fracturing and underground injection wells, and to dam construction and failure, where interactions between an industrial activity and the natural environment may as one system generate highly unpredictable consequences causing what Perrow calls an “ecosystem accident.”63 An example might be increased seismic activity at certain wastewater injection wells. Although the theory of “normal” accidents is based upon on high-risk enterprises and the organizations responsible for their operation, such as nuclear power, aircraft and airways, and marine shipping accidents—where the likelihood of an accident may be relatively small, but the consequences can be drastic—arguably, certain aspects of shale oil and gas exploration carry many of the same risks. While the “interactive complexity” of common high-volume hydraulic fracturing operations may be relatively low and the possibility for failure to cascade unpredictably through the system may, therefore, be limited, certain identified risks do carry the potential to cause an ecosystem accident, as defined by Perrow. Such accidents might include induced seismicity (i.e. earthquakes) and the potential for “fracture intersection” with abandoned or “orphaned” wells, which is “a rare, but known occurrence.”64 103

Normal accident theory rests on the relationship between high-risk systems and organizational structure, finding that failures occur even when operators are doing their best. Other research on accidents highlights certain high reliability organizations, such as aircraft carriers, in which accidents are extremely uncommon when everyone involved is aware, knowledgeable, and attuned to the ramifications of what everyone else is doing. This includes the ability of an organization to manage surprises through an understanding of detail and capacity for action.65 Transposing this more optimistic view of organizations to the development of an unconventional gas well, there are risks inherent in how OFS and operators work together and understand one another’s jobs and how responsibility for safety is distributed and managed. In short, accident risk is not just a function of equipment failure. Organizational form and performance are also important. Attentiveness to safety underlies every aspect of the shale exploration and development process, such as ensuring the integrity of cement casings—not just fracturing.66 This also means that to be effective, regulators—and regulations—need to proactively emphasize training, process, and understanding, rather than merely being prescriptive. To the extent that the BP Macondo incident raises awareness of the possibility of similar accidents in onshore shale exploration, it is important for stakeholders to learn from the BP Macondo failures, including miscommunications, economic pressures, inadequate training, undue reliance 104

upon engineering, and issues of organizational culture, as underscored in the Chief Counsel’s Report.67 In addition, there are lessons from the BP Macondo incident about reliance on regulation and regulatory enforcement that may be pertinent in unconventional shale development.68 A number of questions emerged about the relationship between the offshore drilling industry and regulators, particularly the Minerals Management Service (MMS), which was reorganized and renamed following the blowout and spill.69 As analysts have noted, the approach of MMS to regulating the novel challenges posed by offshore oil and gas developments was premised upon collaboration with major oil companies and equipment vendors in the development of standards, highlighted by the DeepStar Research Project. While MMS cooperated with large, integrated oil companies, it focused its limited resources on the smaller independents launching deep sea operations.70 Thus, MMS was primed to accept these well design changes—however risky. Further, MMS was known to have suffered from a lack of technical capacity due to gaps in employee skills and experience. The agency has consistently had difficulty hiring, training, and retaining experienced staff, which may have compromised its oversight and management responsibilities.71 These challenges have affected the agency’s ability to measure and verify production in particular.72 As the Government Accountability Office recently found, these challenges remain in spite of the reorganization of activities previously overseen by MMS.73

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Whether a similar capacity gap will affect state-level agencies charged with oversight of unconventional oil and gas operations is an ongoing issue, and there have been suggestions of developing new regulatory paradigms. Meehan, for example, has suggested the creation of a new regulatory agency for transitional and clean energy technologies to separate the promotion and regulatory roles of the Department of Energy. Osofsky and Wiseman suggest a range of paradigms to address the current fragmented, yet overlapping, jurisdictions.74 A shale play rarely is located beneath a single state. For example, the Haynesville shale lies beneath the states of Texas, Arkansas, and Louisiana. Well sites may be located beneath more than one state, as well as beneath overlapping local jurisdictions with their separate road regulations, noise, light ordinances, and zoning requirements. As Wiseman notes, industry often has an important claim to technical knowledge associated with unconventional shale oil and gas development and should, therefore, be among the key voices influencing how the process of exploiting these resources unfolds.75 Still, there are pitfalls. In an analysis of industry disclosure of frac fluid chemical composition, Wiseman notes that best practices and other voluntary industry initiatives have several drawbacks. These include the fact that industry itself may not know the full range of risks; the potential that agencies and the public can be “boxed in” by precedents set using industry-derived voluntary standards and agreements; the squelching of voices of non-industry actors; and the fact that they are potentially weighted toward industry needs.76 106

In the substantive realm, efforts by state regulators and industry to work together to identify risks, write guidelines, and propose regulatory changes have been impressive, although not comprehensive…. More consistent efforts to compare gaps among states and regulatory change in response to suggestions from STRONGER [The State Review of Oil and Natural Gas Environmental Regulations], industry groups, scientists and other stakeholders will be needed.77

CONCLUSION This chapter has described broadly the form and organization of companies involved in the upstream segment of unconventional resource development. It has described the entities involved, including fully integrated oil majors, national oil companies, independent operators, and oilfield services companies; shown how relationships among each are structured and risk is apportioned; and introduced some of the actors behind the increasing focus on best management practices. As the ongoing push for use of best practices illustrates, it is increasingly necessary to have a basic understanding of the industry in order to gauge its impacts and effects. NOTES 1. See, e.g., Joe Schremmer, Comment, Avoidable “Fraccident”: An Argument Against Strict Liability for Hydraulic Fracturing, 60 KAN. L. REV. 1215 (2012); Jesica Rivero Gilbert, Assessing the Risks and Benefits of Hydraulic Fracturing, 18 MO. ENVTL. L. & POL’Y REV. 170–208 (2011).

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2. Owen Anderson, The Anatomy of an Oil and Gas Drilling Contract, 25 TULSA L. REV., 359, 382–95 (1989). 3. For a quarterly list of the Top Forty natural gas producers, see Analyses & Studies, NATURAL GAS SUPPLY ASSOC., http://www.ngsa.org/analysesstudies/ (follow “Top 40 Producers: 2012 3rd Quarter” hyperlink) (last visited Mar. 27, 2013). 4. Analyses & Studies, NATURAL GAS SUPPLY ASSOC., http://www.ngsa.org/analyses-studies/ (follow “Top 40 Producers: 2012 3rd Quarter” hyperlink) (last visited Mar. 27, 2013). 5. ROBERT PIROG, CONGRESSIONAL RESEARCH SERVICE, THE ROLE OF NATIONAL OIL COMPANIES IN THE INTERNATIONAL OIL MARKET (Aug. 21, 2007), available at http://www.fas.org/sgp/crs/misc/RL34137.pdf. 6. ERNST & YOUNG, THE OIL DOWNSTREAM: VERTICALLY CHALLENGED? (2012), available at http://www.ey.com/Publication/vwLUAssets/ The_oil_downstream:_vertically_challenged/$FILE/ The_oil_downstream_vertically_challenged.pdf. 7. For Norway’s Statoil, investments abroad, including in U.S. unconventional plays, helped push its 2011 fourth quarter reserve replacement ratio over 100% for the first time in six years. Kari Lundgren, Statoil Net Rises as Reserves Replaced for First Year in Six, BLOOMBERG (Feb. 8, 2012, 11:38 AM), 108

http://www.bloomberg.com/news/2012-02-08/statoilprofit-more-than-doubles-on-assets-sales-oilprices.html). 8. Foreign Investors Play Large Role in U.S. Shale Industry, U.S. ENERGY INFO. AGENCY TODAY IN ENERGY (Apr. 8, 2013), http://www.eia.gov/ todayinenergy/detail.cfm?id=10711. 9.

See, e.g., Our Shale Resources, http://www.statoil.com/en/ouroperations/ explorationprod/shalegas/pages/where.aspx updated July 4, 2013).

Statoil, (last

10. Bloomberg News, China Joining U.S. Shale Renaissance with $40 Billion, BLOOMBERG (Mar. 6, 2013, 6:13 AM), http://www.bloomberg.com/news/ 2013-03-05/china-joining-u-s-shale-renaissancewith-40-billion.html. 11. Joshua Zive, Unreasonable delays: CFIUS Reviews of Energy Transactions, 3 HARV. BUS. L. REV. 169 (2013), available at http://www.hblr.org/wp-content/ uploads/2013/04/Zive_Unreasonable-Delays.pdf. 12. Oilfield Services: The Unsung Masters of the Oil Industry, ECONOMIST, July 21, 2012. 13. Id. 14. Id.

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15. ERNST & YOUNG, REVIEW OF THE UK OILFIELD SERVICES INDUSTRY 2012 (2013), available at http://www.ey.com/publication/ vwLUAssets/ Review_of_the_UK_oilfield_services_Industry_2012/ $FILE/ EY_Review_of_the_UK_oilfield_services_Industry_2012.pdf. 16. Oilfield Services, supra note 12. 17. Oilfield Services, supra note 12. 18. Anderson, Anatomy of an Oil and Gas Drilling Contract, supra note 2, at 364–65.

19. AM. PETROL. INST., CONTRACTOR SAFETY MANAGEMENT FOR OIL AND GAS DRILLING AND PRODUCTION OPERATIONS: API RECOMMENDED PRACTICE 76 (2d ed., 2007), available at http://xa.yimg.com/kq/groups/17553945/ 1282949026/name/ API+Contractor+Safety+Management+Sys+OilandGas+Drilling_76_e2 20. Jacques Bourque, et al., Business Solutions for E&P Through Integrated Project Management, OILFIELD REV., Autumn 1997, at 35. 21. Authors’ interview with Kinnan Golemon, Esq. (Apr. 7, 2013). 22. This section is adapted from Stephane Chafcouloff et al., Integrated Services, OILFIELD REV., Summer 1995, at 11–25, available at http://www.slb.com/~/

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media/Files/resources/oilfield_review/ors95/sum95/ 06951125.pdf. 23. Id. at 11. 24. See, e.g., YCELP, Balancing Environmental, Social and Economic Impacts of Shale Gas Development Activities, VIMEO (Jan. 23, 2013), http://vimeo.com/ 58162903 (video of webinar with Mark K. Boling, Emerging Issues in Shale Gas Development Series, Yale Law School) [hereinafter Boling]. See generally SEC’Y OF ENERGY’S ADVISORY BOARD, SHALE GAS PRODUCTION SUBCOMMITTEE: NINETY-DAY REPORT (Aug. 18, 2011) [hereinafter Subcommittee Report]. 25. C. Newton, P. Cody, & R. Carr, Sourcing Critical Oilfield Services for Shale Plays in a Tightening Supply Market, 231 WORLD OIL, no. 8, Aug. 2010, at 63–66. 26. Boling, supra note 24. 27. The quote is from Thomas Swartz, Hydraulic fracturing: risks and risk management, 26 NAT. RESOURCES & ENV’t, Fall 2011, at 30, available at http://usa.marsh.com/NewsInsights/ ThoughtLeadership/Articles/ID/12717/HydraulicFracturing-Risks-and-Risk-Management.aspx. This section draws upon Chidi Egbochue, Reviewing ‘Knock for Knock’ Indemnities Following the Macondo Well Blowout, 7 Construction L. Int’l, Jan. 2013, at 7–14. 111

28. HARVARD LAW SCH., EMMETT ENVTL. LAW AND POLICY CLINIC, AN OHIO LAND OWNER’S GUIDE TO HYDRAULIC FRACTURING: ADDRESSING ENVIRONMENTAL AND HEALTH ISSUES IN NATURAL GAS LEASES 56–57 (June 16, 2011), available at http://blogs.law.harvard.edu/ environmentallawprogram/files/2013/01/elpc-ohioleasing-guide-v2-june-2011-web.pdf. 29. See, e.g., Thomas West and Cindy M. Monaco, Presentation at the 3rd Law of Shale Plays Conference: Do Conventional Leases Work for Unconventional Plays in Unconventional Times? 18 (June 6–7, 2012) (unpublished manuscript) (discussing the fact that it is increasingly common for leases to include indemnifications between landowners and operators in favor of landowners). 30. Egbochue, supra note 27, at 9–10. 31. LeRoy Lambert, Knock-for-knock contracts are enforceable in the US, STANDARD OFFSHORE BULL., Oct. 2011, at 10. 32. Egobuchue, supra note 27, at 10–11 and n.18. 33. Egobuchue, supra note 27, at 10, 14. 34. Lambert, supra note 31, 10. 35. Authors’ communication with Bruce Kramer, Esq. (July 28, 2013).

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36. Swartz, supra note 27. 37. M. Jokajtys, Insuring Fracking Risk: Can Conventional Insurance Tools Manage Unconventional Risk?, 27 NAT. RESOURCES & ENV’T, Winter 2013, at 1–4. 38. See Swartz, supra note 27, for a discussion of the additional risks to insurers posed by shale gas fracking operations. 39. Douglas McLeod, Fracking Risk Coverage Limited, BUSINESS INSURANCE (Feb. 25, 2013), available at Academic OneFile, File No. 0014. 40. Jokajtys, supra note 37. 41. Jokajtys, supra note 37, at 4. 42. Douglas McLeod, The Coming Conflicts, RISK AND INSURANCE ONLINE (Oct. 1, 2012), http://www.riskandinsurance.com/ printstory.jsp?storyId=533351196. 43. See, e.g., Swartz, supra note 27, discussing involvement of “nonoperating” owners, who may be required under operating agreements to purchase their own insurance programs. 44. Subcommittee Report, supra note 24, at 10. 45. Subcommittee Report, supra note 24, at 6, 10.

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46. Swartz, supra note 27, at 31. 47. Boling, supra note 24. 48. Subcommittee Report, supra note 24, at 26. 49. Boling, supra note 24. 50. Subcommittee Report, supra note 24, at 26. 51. U.S. DEP’T ENERGY, STATE OIL AND NATURAL GAS REGULATIONS DESIGNED TO PROTECT WATER RESOURCES 37 (May 2009). 52. This section draws heavily upon a 2012 presentation by Kathryn Mutz and Bruce Kramer. See Kathryn Mutz and Bruce M. Kramer, Presentation at the 3d Law of Shale Plays Conference: Should Best Management Practices Be Defined By Regulation? (June 6–7, 2012). 53. For instance, the Intermountain Oil and Gas BMP Project (IOGP) maintains a database of both required and recommended BMPs (see http://www.oilandgasbmps.org/). The federal Bureau of Land Management uses BMPs as part of its drilling permit program (see http://www.blm.gov/wo/st/en/ prog/energy/oil_and_gas/ best_management_practices.html). And in the eastern United States, the Marcellus Shale Coalition has identified “recommended practices” that provide guidance on a range of issues, such as water pipelines, motor vehicle safety, pre-drilling water supply surveys,

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and supply chain management, among others (recommended practice documents are available for download at http://marcelluscoalition.org/category/ library/recommended-practices/). 54. Boling, supra note 24. 55. A copy of the draft can be accessed here: http://portal.ncdenr.org/c/document_library/ get_file?uuid=8356eb89-9c9f-4f8ebb4d-4bb51b605575&group Id=8198095. 56. CENTER FOR SUSTAINABLE SHALE DEVELOPMENT, PERFORMANCE STANDARDS (Mar. 2013), available at http://037186e.netsolhost.com/site/wp-content/uploads/ 2013/03/CSSD-Performance-Standards-3-13R.pdf. 57. Kevin Begos, Both Sides Agree on Tough New Fracking Standards, ASSOCIATED PRESS (March 20, 2013, 4:50 PM), http://bigstory.ap.org/article/bothsides-agree-tough-new-fracking-standards. 58. Peter Behr, Authors of Model Fracking Regulation Find that it’s Lonely in the Middle, MIDWEST ENERGY NEWS (Oct. 4, 2012), http://www.midwestenergynews.com/2012/10/04/ authors-of-model-fracking-regulation-find-its-lonelyin-the-middle/. 59. Subcommittee Report, supra note 24, at 9–10 (emphasis in original).

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60. Subcommittee Report, supra note 24, at 10. 61. Hannah J. Wiseman, The Private Role in Public Fracturing Disclosure and Regulation, 3 HARV. BUS. L. REV. ONLINE 49, 66 (2013), http://www.hblr.org/ wp-content/uploads/2013/02/Wiseman_The-PrivateRole-in-Public-Fracturing-Disclosure-andRegulation.pdf. 62. CHARLES PERROW, NORMAL ACCIDENTS: LIVING WITH HIGH-RISK TECHNOLOGIES (1999) (for systems analysis, see ch. 3: Complexity, Coupling, and Catastrophe, 62–100). 63. Id. at 14. 64. See George E. King, Society of Petrol. Eng’rs, Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells (Report No. 152596, 2012), available at http://fracfocus.org/sites/default/files/publications/ hydraulic_fracturing_101.pdf; See also Boling, supra note 24 (for further discussion of earthquake and abandoned gas well risks). 65. Karl E. Weick, Kathleen M. Sutcliffe & David Obstfeld, Organizing for High Reliability: Processes of Collective Mindfulness, in 1 RESEARCH IN ORGANIZATIONAL BEHAVIOR 81–123 (R.S. Sutton & B.M. Staw eds., 1999). 116

66. Boling, supra note 24. 67. NATIONAL COMMISSION ON THE BP DEEPWATER HORIZON OIL SPILL AND OFFSHORE DRILLING, CHIEF COUNSEL’S REPORT, MACONDO: THE GULF OIL DISASTER, at x–xi, 225–50 (2011), available at http://www.oilspillcommission.gov/sites/default/files/ documents/ C21462-220_CCR_Chp_5_Overarching_Failures_of_Management.pdf [hereinafter Chief Counsel’s Report]. 68. See id. at 251, summarizing Chapter 3 of the Full Final Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (available in full at http://www.oilspillcommission.gov/sites/default/files/ documents/4_OSC_CH_3.pdf). 69. While official reports found that BP allowed a number of risky decisions to take place, some of which violated industry best practices, only one—an unusual temporary abandonment design—required MMS approval. Id. at 246. 70. Christopher Carrigan, Captured by Disaster? Reinterpreting Regulatory Behavior in the Shadow of the Gulf Oil Spill, at 40–43 (forthcoming chapter in DANIEL CARPENTER & DAVID MOSS, PREVENTING REGULATORY CAPTURE: SPECIAL INTEREST INFLUENCE AND HOW TO LIMIT IT (Cambridge University Press, 2013)), available at http://www.tobinproject.org/sites/ 117

tobinproject.org/files/assets/ Carrigan%20Captured%20by%20Disaster%20%281.16.13%29.pdf. 71. See U.S. GOV’T ACCOUNTABILITY OFFICE, GAO-11-487T, OIL AND GAS LEASING: PAST WORK IDENTIFIES NUMEROUS CHALLENGES WITH INTERIOR’S OVERSIGHT 5 (2011), available at http://www.gao.gov/assets/130/125795.pdf. 72. See U.S. GOV’T ACCOUNTABILITY OFFICE, GAO-10-313, OIL AND GAS MANAGEMENT: INTERIOR’S OIL AND GAS PRODUCTION VERIFICATION EFFORTS DO NOT PROVIDE REASONABLE ASSURANCE OF ACCURATE MEASUREMENT OF PRODUCTION VOLUMES 68–72 (2010), available at http://www.gao.gov/assets/ 310/301947.pdf. 73. See generally id. at 3 (discussing failure at Interior to incorporate recommendations of GAO during reorganization intended to address “numerous weaknesses and challenges”). 74. Taylor Meehan, Note, Lessons from the PriceAnderson Nuclear Industry Indemnity Act for Future Clean Energy Compensatory Models, 18 CONN. INS. L.J. 339 (2011). See also Hari M. Osofsky & Hannah Jacobs Wiseman, Dynamic Energy Federalism, 72 MD. L. REV. 773 (2013), http://digitalcommons.law.umaryland.edu/mlr/vol72/ iss3/3/; Hari M. Osofsky & Hannah Jacobs Wiseman, Hybrid Energy Governance, U. ILL. L. REV.

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(Forthcoming 2014), available at http://ssrn.com/ abstract=2147860. 75. Wiseman, supra note 61, at 66. 76. Id. at 58, 61–66. 77. Id. at 63.

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PART 2 Legal Issues

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3 Leasing Mineral Rights A Framework for Understanding the Dominant Estate Chad J. Lee and Jill D. Cantway INTRODUCTION

Natural

gas production has exploded throughout the country as the industry discovers new methods of extraction. Despite the rapidly evolving technology, the oil and gas lease has changed surprisingly little in recent years and in many ways is a fairly standard contract. Oil and gas are separate hydrocarbon minerals, but are typically lumped into the same lease document, primarily because both are “fugacious” minerals, which migrate under the earth. Oil and natural gas production has far reaching impacts, from national security to environmental integrity. While state and federal regulations more directly affect the rate of resource production, the content of individual oil and gas leases can significantly impact the effects of exploration on the real property owner, and, cumulatively, the region where exploration is taking place. In this chapter, we first discuss the nature of mineral ownership. Second, we discuss the “nuts and bolts” of oil and gas

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leases. Finally, we address some specific considerations relevant to hydraulic fracturing.

lease

The oil and gas lease is both a conveyance of the mineral estate to the lessee, as well as a contractual relationship between a mineral owner (lessor) and an oil and gas company (lessee). In exchange for an initial bonus payment and/or delay rental payments to the lessor, the lessee has a temporarily vested right for a period of years (the primary term) in which to explore the mineral resource of a property and to drill a well if the lessee determines that developing the resources would be in its economic interest. The lease can be extended to a secondary term if a well is drilled within the primary term and produces oil or gas in paying quantities. This secondary term is typically indefinite in duration, so long as oil or gas is produced in paying quantities or, depending on the language of the lease, as long as drilling operations commenced within the primary term. Royalties are paid to the lessor based on production of the minerals. The oil and gas lease is best viewed as a purely economic transaction where the oil and gas company has two main goals: (1) the right to develop the leased premises without any obligation to do so during the primary term, and (2) the right to maintain the lease for as long as production is economically profitable. The right to develop or not develop the property arises from the reality that the mineral potential of any property is, for the most part, unknown at the time the parties enter into the lease. The right to maintain the lease indefinitely upon the occurrence of certain events specified in the lease, such as oil or gas is being produced, well drilling has begun, or 122

other exploration activities have been initiated, is justified by the significant economic risk taken by the gas company in making the investment to drill the well. Ownership of oil, gas, and other minerals in place is an interest in real property, at least until the minerals are produced, at which point it becomes an interest in personal property. Oil and gas leases reflect the realities of the gas industry, and are very different from commercial or residential leases of real estate. MINERAL INTEREST OWNERSHIP Legally, minerals are part of the real estate. Most lawyers are taught to think of real estate ownership as a “bundle of sticks.” Each stick is a different unit of real estate with certain rights and obligations. For example, the ability to exclude third parties from one’s own land is a “stick” in the bundle. Ownership of the surface, minerals, and easements are all separate sticks in the bundle. Each bundle of sticks is an “estate” in real property. When a landowner owns all the sticks, she owns the “fee” estate, or “fee simple.” More commonly, however, certain “sticks” have been conveyed to third parties in the past, like a utility easement or mineral interest. Often, the minerals have been severed from the surface, meaning the owner of the surface does not own title to the minerals. Only the owner(s) of the minerals can lease those minerals. The mineral estate can become highly complex and severely fractionated, especially in highly developed areas. Usually, the oil and gas company must hire a mineral title attorney to determine the precise interest in the mineral estate. 123

For example, in 1900 the federal government issued a patent, without reservation of any minerals, to Bert for a 40-acre ranch in Colorado called Blackacre. After receiving the patent, Bert owns the entire “fee estate,” or 100 percent of the surface and the minerals. In 1940, Bert sells Blackacre to Andy. Understanding the value of minerals, Bert reserves half of the mineral estate to himself. After this conveyance, Andy owns 100 percent of the surface, but only a 50 percent interest in the minerals. Conveyances and reservations of minerals typically continue on down the chain of title until we get to the present day. For example, upon Bert’s death, his 50 percent interest in the minerals vests in his four children, three of whom sell to third parties and one of whom conveys his interest to his four children, reserving a life estate to himself. Additionally, when Andy sells Blackacre, he reserves 50 percent of his interest in the minerals (which is actually 25 percent because he only initially owned 50 percent). Later, Andy sells only that part of his mineral interest in Blackacre above a certain horizon (or depth) under Blackacre, let’s say 5,000 feet. These types of conveyances can continue, potentially resulting in very large numbers of mineral owners with each owning a different interest in the minerals under a given surface estate. There are other potential mineral interests that can be created by specific conveyances or reservations, including various kinds of royalty interests, production payments, and net profits interest. For example, a nonparticipating royalty interest is an interest in only the percentage share of the values of the minerals sold, but without any decision-making authority regarding leasing, exploration, 124

or development. These types of interests are all permutations of the mineral estate. Most of these interests exceed the scope of this chapter, but the reader should be aware of the variety of interests that can be created within the mineral estate. Oil and gas companies will generally research the mineral title and obtain oil and gas leases from all mineral owners prior to drilling. If they do not obtain a lease from a mineral owner, there are force pooling statutes and other exceptions (discussed elsewhere in this book, including chapter 4) that would apply to the unleased mineral owner’s share of the minerals. After the minerals are produced and sold, the lessee pays royalties to the mineral owners in proportion to their ownership of the mineral estate. Another major “stick” in the mineral interest bundle is the implied easement to use the surface. The law implies an easement that every mineral owner (or its lessee) can use as much of the surface as is reasonably necessary to obtain the minerals under the property. This is discussed in depth below. This easement is implied by necessity; without it the mineral estate would be worthless because the surface owner would have the ultimate “veto power.” In fact, in most states, courts consider the mineral estate to be even more important than the surface estate.1 The historical justification for the superiority of the mineral estate is that the minerals cannot be moved, whereas activities on the surface can be relocated, at least temporarily, to permit the minerals to be removed.

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But mineral owners (or their lessees) cannot use the surface with impunity. In most states the mineral owner is required to, at minimum, “reasonably accommodate” the surface owner. Some states have gone further and have enacted statutes codifying this doctrine and granting further rights to surface owners. For this reason, surface owners are often approached by oil and gas companies to enter into surface use agreements, which, as the name implies, dictate the oil and gas company’s use of the surface of the property. Conversely, the surface owner also typically has certain rights that extend below the surface, even if they do not own any of the minerals underlying their property. The surface owner generally has rights to potable groundwater, subsurface support, and potentially even rights to use geologic formations for the storage of natural gas.2 LEASING IN GENERAL Prior to drilling, the oil and gas company will usually first obtain an oil and gas lease from each of the owners of the minerals underlying a prospective location. Depending on how fractionated the minerals are, the gas company may have to negotiate and obtain many leases. The lease gives the oil and gas company the right to explore and develop the minerals. The wording of each lease is important and determines the precise interests that are leased. As with other contracts, the parties are free to enter into whatever bargain they choose, so long as the terms are sufficiently definite to be enforceable. 126

LEASE FORMS AND THE MYTH OF THE “PRODUCER’S 88” Many mineral owners are first approached by a “landman” to lease their mineral interest. A landman is either an agent of an oil and gas company or an independent contractor who will later sell the lease to an oil and gas company. Most mineral owners would be wise to consult with an attorney prior to executing any lease. Unfortunately, most do not. Most also have a mistaken assumption that there is a standard oil and gas lease form called the “Producer’s 88.” This myth has been perpetuated because leases commonly contain a notation in the upper margin of something like ‘Producer’s 88-Revised.’ But there is no uniform industry standard lease, and the “Producer’s 88” generally refers to a lease form with terms favorable to the gas company.3 BASIC PRIVATE (FEE) LEASES Unlike commercial or residential real property leases, courts generally treat an oil and gas lease as both a conveyance of the mineral rights and a contract between the mineral owner (lessor) and the oil and gas company (lessee) for the development of the minerals. Oil and gas leases are different from real property leases in three main ways: (1) the lessee has the right not only to use the land, but also extract substances of value from it; (2) the lessee’s rights are not normally limited by a specific term; and (3) the lessee’s rights to use the land are not exclusive and must be shared with the surface owner.4 Because oil and gas leases are considered to be conveyances of real property, the lease must be in writing or otherwise satisfy 127

the Statute of Frauds. The lessee will also record either the lease itself or a “memorandum of lease” in the county records in order to provide notice of the lease to third parties. There is some variation from state to state in the classification of the property interest conveyed by the oil and gas lease, but the interest is most commonly a conveyance of real property. In Texas, a leasehold interest is an estate in fee simple determinable to the oil and gas in place.5 In other states, including Oklahoma and Wyoming, the lessee’s interest is called a profit a pendre,6 whereas Pennsylvania classifies a lessee’s interest as an inchoate right, which may become vested only after production.7 Notwithstanding this disparate legal treatment, oil and gas leases create a surprisingly uniform relationship between the lessor and the lessee, and all include a few indispensible terms. An oil and gas lease must generally contain four clauses: the granting clause, the habendum clause (the term), the drilling-delay rental clause, and the royalty provision.8 There are other miscellaneous clauses that can also be inserted into the lease and several implied covenants, some of which we will discuss below. Typical formulations of these clauses are presented below, together with a discussion of their implications. The Granting Clause Lessor in consideration of $_______ per net mineral acre in hand paid, of the royalties herein provided, and of the agreements of Lessee herein contained, hereby grants, leases, and lets

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exclusively unto Lessee for the purposes of investigating, exploring, prospecting, drilling, and mining for and producing oil, gas, and all other minerals, conducting exploration, geological and geophysical surveys by seismograph, core test, gravity and magnetic methods, injecting gas, water and other fluids, and air into subsurface strata, laying pipelines, building roads, tanks, power stations, telephone lines, and other structures thereon, and on, over, and across lands owned or claimed by Lessor adjacent and contiguous thereto, to produce, save, take care of, treat, transport and own said products, and housing its employees, the following land….

or, simply: Lessor leases to Lessee for the purposes of exploring and producing oil and gas and other liquid and gaseous hydrocarbons, compounds, and byproducts produced therewith, the following lands….

The granting clause defines the specific substances and lands leased and grants the right to explore, develop, and produce oil and gas from the lands, without the obligation to do so. Because other valuable substances are produced as byproducts of oil and gas production, many courts have struggled to decide which substances are covered by oil and gas leases. To avoid disputes, oil and gas leases should be specific as to which substances are covered. In general, references to all “oil and gas and all other hydrocarbons” or “oil, gas, and all other minerals” will apply to all liquid and gaseous hydrocarbons, even if they are not considered to be oil or gas. Further, as with all deeds conveying interests in real property, the lease must describe the leased lands sufficiently such that a reasonable person can locate the 129

parcel. Street addresses and assessor’s parcel numbers are generally insufficient, whereas metes and bound descriptions or references to specific quarter sections, townships, and ranges are preferred. The granting clause also conveys the right to explore for and develop the minerals. We should note that in some cases, an oil and gas company will negotiate a surface use agreement with the surface owner of the lands on which they plan to drill. Such an agreement may specify the type and location of surface uses allowed. In the absence of such agreement, the oil and gas company (lessee) is accorded considerable discretion in using the surface and subsurface of the leased property. But this discretion is not unlimited. Courts have limited a lessee’s activities on the leased property by at least five doctrines: (1) reasonable use, (2) the accommodation doctrine, (3) for the benefit of the minerals in place; (4) the terms of the lease; and (5) all applicable statutes, ordinances, rules, and regulations.9 Limitations on Oil and Gas Company Activity An oil and gas lease conveys to the oil and gas company an implied right to reasonable use of the surface to locate, develop, and produce oil and gas from the property. The oil and gas company, in other words, has an implied easement to use the surface of the land in such ways and at such locations as may be reasonably necessary to obtain the minerals.10 Many surface owners are surprised by the breadth of this implied easement, as it accords considerable discretion to oil and gas companies to utilize

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almost all aspects of the surface estate which do not directly interfere with the surface owners current uses. Surface owners should familiarize themselves with the types of infrastructure necessary to complete a modern well. Hydraulic fracturing, in particular, adds several steps to the process, including the use of more pits, tanks, and equipment on the surface, the application of fluid and chemicals to the well after drilling, and the production of a type of waste called “flowback” water.11 The implied easement in an oil and gas lease permits the lessee to conduct hydraulic fracturing in the absence of an express provision to the contrary. Of course, it also permits more traditional oil and gas operations. What this means for surface owners is that once the minerals are leased, the oil and gas company has a legal right to access the surface estate, conduct seismic and other exploratory tests, build roads, construct drilling sites, and erect structures associated with oil and gas production including storage tanks, compressor stations, waste pits, and pipelines.12 It even permits the oil and gas company to use certain surface resources, such as water and building materials, in some cases.13 Nonetheless, any activity that exceeds the scope of the easement is a trespass, for which the surface owner can seek damages. Oil and gas companies have been held liable for a number of trespass-related claims, including negligent pollution and nuisance for failure to plug abandoned wells and remove equipment.14 What constitutes a trespass depends on the unique facts and circumstances of the situation, which is a question of fact for a jury, and typically the burden is on the surface 131

owner to prove any type of trespass-related action.15 Recently, however, oil and gas companies have become acutely aware of the changing societal norms of “reasonable use” under an oil and gas lease, and typically operate accordingly. This implied easement may be expanded, of course, by written agreement between the surface owner and oil and gas company. This could occur through a separate easement, such as a pipeline easement, a surface use agreement, or it may be included in the granting clause of the lease (if the mineral owner also owns the surface). Under the “accommodation doctrine,” mineral lessees must also accommodate surface use wherever possible. Under common law, the intent of the parties in severing the minerals was that both the mineral owner and the surface owner would have valuable estates.16 In order to protect the value of the surface, oil and gas companies should be required to accommodate surface uses whenever reasonable. The accommodation doctrine varies state by state. For example, in Texas for the doctrine to apply (1) there must be an existing surface use; (2) the proposed mineral activity must substantially interfere with the existing surface use; and (3) the oil and gas company must have reasonable alternatives.17 The burden is on the surface owner to prove there are alternative means to develop the mineral estate.18 In Colorado, on the other hand, a mineral owner (or gas company) must have “due regard” for the surface estate and must select alternate methods of production which mitigate the impacts of production on the surface

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estate, but only if those alternatives are “economically practicable.”19 An oil and gas company must also limit use of the surface to those uses exclusively intended to obtain minerals from under the lands leased, i.e., their activities on the surface must be “for the benefit of the minerals in place.” For example, if an oil and gas company leases two adjoining tracts, it cannot install a pipeline across one tract to access minerals produced on the adjacent tract (unless it is also producing oil or gas from the first tract under a pooled unit, for example).20 Recent developments in horizontal drilling and hydraulic fracturing have intensified the surface operations of oil and gas drilling. Horizontal drilling permits the capture of oil and gas from a smaller footprint, though it intensifies the use of that footprint. Given the use of these techniques, the dominance of the mineral estate may become even more apparent in the future. Lease Terms and Regulatory Restrictions Just as in any other contract, the terms of the lease can modify the above-described common law rights and obligations between the parties. Some leases specifically limit the surface use of the parcel or contain a no surface occupancy (NSO) stipulation. An NSO stipulation is an agreement in an oil and gas lease prohibiting any sort of occupancy or disturbance on all or part of the leased lands in order to protect special values on the surface estate. Note that the lessee may develop the oil and gas estate 133

through the use of directional or horizontal drilling from outside the area subject to the NSO stipulation. Occasionally, the parties will enter into an NSO stipulation in the lease and then enter into a surface use agreement later. The oil and gas company’s activities are also limited by statute. Local, state, and federal governments routinely impose restrictions on an oil and gas company’s implied right to use the leased property. Generally, courts have held these restrictions to be valid exercises of the state’s police power. In New York, for example, the courts have generally permitted municipalities to prohibit oil and gas operations within their borders under the guise of land use regulations.21 However, some local governments may be preempted from imposing certain restrictions, especially technical restrictions.22 In any event, preemption is a rapidly emerging field of oil and gas law, which has reemerged in the wake of America’s current “energy renaissance.” Additionally, some states have enacted surface damage acts, some of which require oil and gas companies to pay damages for their use of the surface.23 These statutes reverse the common law that a mineral interest owner is entitled to reasonable use of the surface to obtain the minerals without the landowner’s permission and without payment. Surface damages acts may become even more important now that hydraulic fracturing is mainstream. States will likely enact or update their acts in the next few years in response to the public outcry over the use of hydraulic fracturing.

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The Habendum (Term) Clause This Lease shall be for a term of _____ years from this date, call the “primary term,” and as long thereafter as oil or gas are produced.

or, This Lease shall be in effect for and during the Primary Term and as long thereafter as minerals hereunder are produced in paying quantifies from the Leased Premises or the Land Unitized herewith.

The habendum clause defines the term of an oil and gas lease. Typically, this clause includes a defined primary term and a contingent secondary term.24 During the primary term, the oil and gas company may hold the lease without actually drilling. In general, the primary term is the maximum period during which the oil and gas company can hold the lease without drilling. The purpose of the primary term is to provide the oil and gas company with sufficient time to complete geologic and geophysical testing, drill a test well, or arrange for financing and other support services necessary to drill. The length of a primary term is a function of the market. As a general rule of thumb, the primary term in non-proven or marginally producing areas is between five and ten years, and the primary term for established and proven areas is between one and five years. The primary term can be cut short by surrender of the lease by the oil and gas company or failure to pay delay rentals, if applicable.

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The secondary term extends the lease beyond the primary term in the event of production in paying quantities for as long as it is economically viable to do so. Usually the secondary term is an indefinite period of time, but occasionally maximum time limits are attached to secondary terms. Courts differ on the interpretation of “production” sufficient to extend the lease into a secondary term. In general, courts view oil and gas leases as purely economic transactions. With this in mind, the majority view requires marketing of the oil and/or gas in addition to production “in paying quantities.” However, other states hold that an oil and gas lease will not terminate if oil or gas is discovered prior to the end of the primary term so long as the lessee makes diligent efforts to complete the well, produce the minerals, and market the same.25 Production “in paying quantities” is often difficult to apply in practice. In Texas, for example, the standard is whether, under all the relevant circumstances, a reasonably prudent operator would, for the purpose of making a profit, continue to operate the well.26 More discussion on this issue is included below regarding shut-in gas royalty clauses. The Drilling Delay Rental Clause If operations for drilling are not commenced on said land, or on acreage poled therewith as above provided for, on or before one year from the date hereof, the Lease shall terminate as to both parties, unless on or before such anniversary date Lessee shall pay or tender to Lessor the sum of $______ which shall cover the privilege of deferring commencement of drilling operations for a period of twelve months. In like manner and upon the payment or

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tender annually, the commencement of drilling operations may be further deferred for successive period of twelve months each during the primary term hereof …

This clause ensures that the lessee has no obligation to drill during the primary term by negating any implied obligation to test the premises. Without this clause, many courts held that the oil and gas company had an implied duty to drill a test well on the leased premises within a reasonable time after grant of the lease. When an oil and gas lease is extended by the drilling of a well, disputes can arise about whether drilling occurred in a timely manner (i.e., whether it occurred before the expiration of the primary term of the lease). Courts resolve these disputes by looking at the precise language of the lease, the good faith of the oil and gas company, and the oil and gas company’s due diligence. To complicate matters, most leases require that the oil and gas company merely commence operations for drilling before the anniversary date to preserve its rights.27 A delay rental clause provides that if a well is not drilled, the lessee must make delay rental payments. Delay rental payments require strict compliance. The oil and gas company must ensure rentals are paid in the proper amount, on or before the due date, to the proper parties, and in the manner prescribed by the lease. These days, however, many leases are “Paid-Up,” meaning that all delay rental payments are paid up front, as in this example:

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This is a PAID-UP LEASE. In consideration of the down payment, Lessor agrees that Lessee shall not be obligated, except as otherwise provided herein, to commence or continue any operations during the primary term, or to make any rental payments during the primary term…. (emphasis added).

In Paid-Up leases, all rentals are paid up front, and the lease is held for the full primary term by the initial payment to the lessor. The Royalty Clause The royalties to be paid by the Lessee are: … (b) to pay Lessor on gas and casinghead gas produced from said land (1) when sold by Lessee at the well, 1/8 of the amount realized by Lessee, or (2) when used by Lessee off said land or in the manufacture of gasoline or other products, 1/8 of the amount realized from the sale of gasoline or other products extracted therefrom and 1/8 of the amount realized from the sale of residue gas after deducting the amount used for plant fuel and/or compression.28

The royalty provision is perhaps the most important clause for the mineral owner. It provides the mineral owner with a share of the production from any well drilled on the property or on lands pooled or unitized therewith. Royalties are only paid when oil or gas is actually produced in paying quantities under the lease, which means that only around 10 percent of lessors nationwide will ever see royalties.29 Nonetheless, the potential for lucrative income makes this the most important part of the lease. Most mineral owners think of the royalty in terms of a raw percentage. Oil and gas companies typically begin negotiations at 1/8, but royalties of up to 1/5 or more are

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becoming increasingly common. The flexibility of the oil and gas company depends entirely on the market and the type of “play” at issue. Higher royalties are possible in proven areas and some leases even provide for a sliding scale based on production. However, the sheer percentage of royalties is merely the first step in drafting a royalty clause. Perhaps more important is the method by which the royalty is calculated. Without this calculation, the raw percentage means little, if anything. Gas royalty clauses generally fall in to three types: proceeds, market value, and a hybrid of these two. The “proceeds” clause makes royalties payable based on the actual proceeds received by the oil and gas company in the sale of the gas. Often, given the realities of the gas market, the oil and gas company’s proceeds from the sale of gas are actually much less than the current fair market value, especially where the oil and gas company enters into a long term contract to sell to a certain supplier. The proceeds clause is preferred by the oil and gas company and is perhaps the most fair to both parties.30 The “market value” royalty clause makes a gas royalty payable on the market value of gas at the time it is produced from the well. Defining market value has proven difficult and is often a flashpoint between lessor and lessee.31 Lessors argue that market value means the market value of the gas at the time it is produced and sold. Oil and gas companies, on the other side, often enter into long-term contracts to sell gas at a favorable price, and therefore as long as a lessee can demonstrate it acted prudently in entering into the long-term contract, the price received under the contract should be deemed at the 139

market value.32 For this reason, oil and gas companies typically disfavor market value royalty clauses, whereas mineral owners generally prefer them. The third category is simply an alternative clause, which provides a proceeds basis for some types of sales and a market value basis for others. Another necessary consideration is whether to allow the oil and gas company to deduct certain types of expenses after the gas is produced from the proceeds before calculating the royalty. Gas produced from the well is often not marketable in its current state. The oil and gas company must expend money to treat, compress, process, transport, and dehydrate the gas. Deducting these costs from the royalties can result in much lower proceeds for a mineral owner. Under most royalty clauses, a lessee is obligated to pay all costs of production, but the lessor shares proportionately in costs after production, because these ordinarily increase the value of production. But there is dispute over when “production” has occurred. The conventional analysis holds that production occurs for royalty-calculation purposes when oil or gas is captured and held at the wellhead.33 An increasingly popular view, on the other hand, is the “first marketable product rule,” which holds that “production” is not complete for royalty-calculation purposes until a lessee has both captured and held the product and made it marketable.34 From the mineral owner’s point of view, the ideal royalty clause would provide for a royalty based on the fair market value of the gas, calculated at the point of marketing without deductions for the costs of producing, gathering, storing, separating, treating, dehydrating, 140

compressing, processing, transporting, or otherwise making the gas, oil, and other products produced ready for sale or use.35 As a fallback, mineral owners could request a proceeds clause based on a gas sales contract entered into in good faith and at arm’s length. In any event, the parties should find a compromise that will provide certainty, incentivize production, and avoid litigation in the long run. Gas royalty clauses have perhaps caused more litigation than all of the other clauses combined, probably because there is so much at stake. Nonetheless, most royalty provisions remain fairly ambiguous. The technical issues surrounding royalty clauses are beyond the scope of this chapter. The reader should be mindful of the general issues surrounding the construction of a royalty clause and may consider requiring the oil and gas company to provide monthly accounting of royalties to the mineral owner. OTHER IMPORTANT LEASE TERMS Warranty Clauses The oil and gas company may request a warranty of title by the mineral owner to the minerals. However, prior to warranting their interest in the minerals, a mineral owner should ensure that he does in fact own the entire mineral interest stated in the lease. If there is any uncertainty, the warranty clause should be modified or deleted. Mineral owners who are uncertain of their mineral interest are wise to include a disclaimer of warranty. For example:

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This Lease is made without any covenant of title or warranty of any kind whatsoever and without recourse against Lessor.

Typical leases also include a “lesser interest” clause, which diminishes the interest of a mineral owner down to his or her actual interest in the mineral estate. This permits the oil and gas company to pay royalties and other payments in proportion to the mineral owner’s actual interest in the property. Mineral owners should ensure that a lesser interest clause applies only to the royalty and not the bonus or other rental payments. Shut-In Clauses If for a period of 90 consecutive days such well or wells are shutin or production therefrom is not being sold by Lessee, then Lessee shall pay shut-in royalty of twenty five dollars ($25.00) per acre then covered by this lease, such payment to be made to Lessor or to Lessor’s credit in the depository designated below, on or before the end of said 90-day period and thereafter on or before each anniversary of the end of said 90-day period while the well or wells are shut-in or production therefrom is not being sold by Lessee; provided that if this lease is otherwise being maintained by operations, or if production is being sold by Lessee from another well or wells on the leased premises or lands pooled therewith, no shut-in royalty shall be due until the end of the 90-day period next following cessation of such operations or production.

A shut-in clause permits an oil and gas company to hold a lease during its secondary term when the well is drilled but is not producing in paying quantities. In other words, it is “shut in.” If the market value of gas has significantly decreased to the point that it is no longer profitable to produce, oil and gas companies will often 142

“shut-in” (or turn off) wells. A shut-in well could also occur where an oil and gas company is on a “wildcat” play and there is no pipeline or other infrastructure to transport the gas to market. After undertaking substantial up-front investment to drill the well, the lease would technically lapse without production in paying quantities. To remedy this, a shut-in clause permits oil and gas companies to hold a lease during its secondary term after a well has been drilled upon payment of a certain sum to the mineral owner instead of actual production. Shut-in clauses should provide certainty and should be drafted in light of the lessor and lessee’s goals. Shut-in payments do not release the lessee from other implied obligations, such as the obligation to reasonably develop the property. The clause may contain an obligation that the oil and gas company act diligently to produce and market the gas from a shut-in well. Pooling and Unitization Oil and gas companies often need or desire the flexibility to combine several leased tracts into a producing unit. A producing unit is a defined geographic area, usually set by the state oil and gas commission, from which all mineral owners are paid in proportion to their ownership within the unit. Oil and gas companies accomplish this by pooling, which is the bringing together of small tracts for the drilling of a single well for production from the pooled unit. Unitization refers to combining leases and

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wells over a producing formation for field wide operations. Pooling clauses are important to the oil and gas company. Without one, the oil and gas company cannot extend the lease into its secondary term without drilling a well on the actual leased property, even if spacing rules would not permit a well to be placed there or geological evidence suggests drilling would be unsuccessful (unless they receive written consent to pooling from the lessor). If a well were drilled on a lease without a pooling clause within a producing unit (or without the lessor’s consent to pooling), the oil and gas company would have to account to the lessor for the entire full lease royalty on production from the well, even though the lessor may only be entitled to a portion of it. A pooling clause modifies the habendum clause by stating that production or operations anywhere in the pooled unit will be considered to be production or operations on the lease premises for purposes of the secondary term. In essence, it establishes constructive production. A pooling clause obligates a mineral owner to accept a royalty proportionate to the amount of the leased land included in the pooled unit, protecting the oil and gas company from having to make double royalty payments. From a mineral owner’s perspective, pooling clauses are not per se objectionable, but should be carefully worded. Oil and gas companies must act in good faith when pooling lands. To avoid potential problems, some mineral owners insist on simply removing the pooling clause (in which case the lessor would have to separately consent to pooling) or adding a Pugh clause. 144

As noted above, even if the pooling clause is removed from a lease, an oil and gas company can request that a mineral owner consent to voluntarily pooling if it is in both parties’ interests. Alternatively, most states have compulsory pooling statutes that permit the oil and gas company to request that all lands within a spacing unit to be compulsorily pooled. These “Force Pooled” statutes are most often used to pool any unleased mineral interests within the pooled unit. Pugh Clauses A “Pugh” clause is not standard, but it can be negotiated into the lease. It limits the acreage that is held by production in the secondary term to that acreage which lies within a pooled unit. At the end of the primary term, portions which are not part of a producing well’s (or a shut-in well’s) spacing unit are released from the lease. Pugh clauses can be horizontal and/or vertical. A vertical Pugh clause divides the leasehold strictly on the basis of the surface acreage included in a well spacing unit. A horizontal Pugh clause limits the area held by production to the producing strata and shallower (or deeper) strata in the unit. These clauses can be difficult to negotiate. A suitable alternative could be for mineral owners to only lease their interest in and to any minerals in smaller parcels (for example, the mineral owner would execute one lease for each section, or even quarter-section, in which they own minerals), even if they own a larger parcel (mineral owners doing this should be sure that the “Mother Hubbard” clause, which automatically includes any adjacent property the lessor may own, is deleted).36

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Force Majeure Clauses A force majeure clause permits the oil and gas company to preserve the lease when circumstances beyond its control prevent it from operating. Commonly covered events include acts of God or war. Mineral owners should pay attention to these clauses and carefully word and define the events covered. The oil and gas company should bear the burden of market conditions or adverse government regulations. Further, these clauses should have limited time and application, such as not more than one year, and the oil and gas company should have an obligation to make a good faith effort to overcome the condition. Implied Covenants of Oil and Gas Leases Despite the wording of an oil and gas lease, some courts have held that oil and gas companies are bound by implied terms in addition to those written into the lease, although most states will not find an implied covenant where the lease includes an express covenant in a given area. These implied covenants are unwritten conditions by which the oil and gas company is bound. Typically these implied covenants are designed to protect lessors. At the heart of these implied covenants is that the oil and gas lease is an economic transaction and both parties should be appropriately incentivized to develop the lease in a reasonable manner. Below is a brief discussion of some of the more common implied covenants.

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Lessees are required to conduct themselves as a reasonable and prudent operator under the circumstances. This requirement underlies all other implied covenants. Originally, this covenant was intended to make it clear that while the oil and gas company’s obligation is less than that of a fiduciary, it is more than an obligation to act in good faith. It requires different duties in different circumstances, but it generally requires the oil and gas company to act (1) in good faith, (2) competently, and (3) with due regard for the lessor’s interest. Other covenants are also commonly implied. The implied covenant to reasonably develop imposes an obligation on the oil and gas company to reasonably develop the mineral estate in the same manner as an economically motivated prudent operator.37 The implied covenant for further exploration imposes a general obligation on the oil and gas company to explore undeveloped parts of the leased estate or strata under the land.38 The implied covenant to protect against drainage imposes an affirmative duty upon the oil and gas company to protect the leased lands from drainage of the minerals by adjacent parcels.39 Finally, the implied covenant to market requires that the oil and gas company diligently market oil and gas within a reasonable time of production and at a reasonable price.40 All of these covenants are judicially created implied obligations. SPECIAL LEASE CONSIDERATIONS FOR HYDRAULIC FRACTURING While some states and municipalities have begun to consider certain limitations on the use of hydraulic 147

fracturing techniques as discussed in other chapters of this book, typically the right conveyed in the oil and gas lease encompasses the use of hydraulic fracturing techniques unless specifically prohibited by the lease. As such, mineral owners may consider negotiating special terms when hydraulic fracturing is anticipated. Hydraulic fracturing, together with horizontal drilling techniques, typically results in higher intensity use of the surface than traditional oil and gas operations. It may also pose a greater risk of surface and subsurface contamination from fracturing chemicals and flowback wastes.41 Hydraulic fracturing operations certainly increase the potential for greater surface damage to infrastructure, such as roads, because of the larger amount of equipment and fluids that must be brought to, stored on, and removed from the site. The increased traffic associated with hydraulic fracturing may also present safety concerns and may negatively impact public and private roads.42 Lessees may consider inserting baseline and remedial provisions to protect private roads and other infrastructure after drilling and recovery operations have completed. In order to protect themselves, lessors and lessees alike may consider adding certain stipulations into the lease terms, such as baseline water testing and monitoring. This allows both parties to monitor the health of the ground and surface water during the lease term. Other protective terms could include remediation or bond requirements that exceed those required by the state regulatory agencies, or the requirement to disclose the types of chemicals used onsite, including in the fracturing fluid. Note, however, that some states have already begun to require the disclosure of the chemical solutions used in 148

hydraulic fracturing operations,43and many industry parties are participating in voluntary disclosure programs. A Note on Negotiation Technique Negotiations for oil and gas leases should be collaborative endeavors, rather than adversarial. Both parties should seek to determine the other party’s needs, interests, and concerns and address each in a clearly worded lease document. The oil and gas company, obviously, seeks the right but not the obligation to develop for the greatest amount of time. The mineral owner, on the other hand, seeks economic profit, but also (especially if the mineral owner is also the surface owner) domestic tranquility and minimal harm to the surface estate. A mineral owner’s opportunity to negotiate many of the terms described above depends to a large extent on the type of subsurface mineral rights involved and the current oil and gas market. Surface Use Conditions in Oil and Gas Leases A mineral owner who also owns title to the surface estate has an opportunity to protect his or her interests in the surface estate at the time of the execution of the lease. Several considerations are discussed below. There is no common law right for a surface owner to be compensated for the oil and gas company’s reasonable and necessary use of the surface. Nonetheless, in the interest of goodwill, the oil and gas company may compensate and work with the surface owner.

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There are several provisions that can protect the surface estate, which may be incorporated into the lease or in a separate surface use agreement. The goal of any surface owner should be to define and locate as many of the potential uses of the surface as possible and to protect baseline resources. Some considerations include: (1) access to, testing of, and use of water resources on the property; (2) repair and compensation for surface damage to things such as timber stands and crops and other sitespecific assets; (3) distance of surface operations from structures; (4) road location and construction review by landowner and a qualified engineer or forester; (5) possible timing of surface operations to allow for livestock pasturing, hunting, or other rural land activities; and (6) bonded environmental remediation requirements with firm time limitations.44 Many jurisdictions have passed statutes intended to protect surface owners. Some are simply codifications of the common law accommodation doctrine,45 while others require compensation to the surface owner for surface use and damage.46 CONCLUSION Oil and gas leases create a unique and often complicated relationship between the mineral owner and the oil and gas company. Mineral owners often have sufficient leverage to negotiate certain terms of the lease, but the respective party’s leverage ultimately depends on market conditions. NOTES 150

1. In legal terms, the mineral estate is the “dominant” estate. See, e.g., Hunter v. Rosebud County, 783 P.2d 927 (Mont. 1989). 2. See, e.g., Emeny v. United States, 412 F.2d 1319 (Ct. Cl. 1969) (holding oil and gas lessee did not acquire right to store in closed geological structure or underground dome underneath leased premises helium gas and pure helium produced elsewhere.); Moser v. U.S. Steel Corp., 676 S.W.2d 99, 102 (Tex. 1984) (confirming the following materials are part of the surface estate unless specifically leased: building stone and limestone; limestone, caliche, and surface shale; water; near surface lignite, iron and coal; cf. Hicks Exploration v. Okla. Water Res. Bd., 695 P.2d 498, 504 (Okla. 1984) (holding owner of surface estate owns the underlying fresh groundwater, but surface estate is subject to the mineral owner’s right to use reasonable amounts of the water for production of minerals). 3. The designation ‘Producer’s 88’ derives from lease version created to circumvent a 1916 Oklahoma decision. “Producers” indicates it was used by oil producers; “88” was merely the printer’s designation. The original “Producer’s 88” form did spread in popularity in the early 20th Century, but each company now has its own preferred form of lease, most of which they still call the “Producer’s 88.” Practitioners should use caution when referring to “Producer’s 88.” In Fagg v. Texas Company, the court refused to grant specific performance on a contract that required one of the parties to enter into an oil and gas lease on an “88 151

form” because this was insufficient to meet the Statute of Frauds. The court noted in dicta that the “88 form” was no more descriptive than the term “oil and gas lease” used alone. Thus, despite the widespread misconception that “Producer’s 88” describes some ubiquitous industry standard form, it does nothing more than indicate the form was drafted by the oil and gas company. This notation persists today only as an indication that the lease was designed with the oil and gas company (the lessee) in mind. For more information, see Owen L. Anderson, David V. Goliath: Negotiating the ‘Lessor’s 88’ and Representing Lessors and Surface Owners in Oil and Gas Lease Plays, Proceedings of the Rocky Mountain Mineral Law Institute, Seventh Annual Institute (1982), at II (D) (discussing Brown v. Wilson 160 P. 94 (Okla. 1916) (holding an oil and as lease with an ‘or’ form rental clause was voidable at the option of both parties and merely created a tenancy at will)). 4. JOHN S. LOWE, OIL AND GAS LAW 172 (Nutshell Series, 4th ed. 2003). 5. See Jupiter Oil Co. v. Snow, 819 S.W.2d 466 (Tex. 1991). 6. See Hinds v. Phillips Petrol. Co., 591 P.2d 697 (Okla. 1979). 7. See, e.g., Hite v. Falcon Partners, 13 A.3d 942 (Pa. Super. Ct. 2011).

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8. See, e.g., David E. Pierce, Rethinking the Oil and Gas Lease, 22 Tulsa L.J. 445 (1987); LOWE, supra note 4, at 173. 9. Lowe, supra note 4, at 179. 10. See Hunt Oil Co. v. Kerbaugh, 283 N.W. 2d 131 (N.D. 1979). 11. See Hannah Wiseman, Beyond Coastal Oil v. Garza: Nuisance and Trespass in Hydraulic Fracturing Litigation, 57 ADVOCATE (Texas) 8 (2011). 12. LOWE, supra note 4, at 179. 13. See generally Douglas Hale Gross, What Constitutes Reasonably Necessary Use of the Surface of the Leasehold by a Mineral Owner, Lessee, or Driller Under an Oil and Gas Lease or Drilling Contract, 53 A.L.R. 3d 16 (2013); Robinson v. Robbins Petroleum Corp., 501 S.W.2d 865, 867 (Tex. 1973) (holding the lessee was entitled to “use of the salt water which was reasonably necessary to produce oil under” the surface estate, if any, but was liable to the plaintiff for “that portion of the salt water which has been consumed for the production of oil for owners” of adjoining mineral estates); P.G. Guthrie, Construction of Oil and Gas Lease Provision Giving Lessee Free Use of Water From Lessor’s Land, 23 A.L.R.3d 1434 (2013). 14. See, e.g., Wiseman, supra note 11; Brown v. Lundell, 344 S.W.2d 863 (Tex. 1961) (pollution to 153

groundwater); Beyond Coastal Oil v. Garza: Nuisance and Trespass in Hydraulic Fracturing Litigation, 57 ADVOCATE (Texas) 8, 10 (2011). 15. See Key Operating & Equip., Inc. v. Hegar, 01-10-00350-CV, 2013 WL 103633 (Tex. App. 1st 2013) (imposing the burden on the landowner to prove use of road was not related to development of subsurface estate). 16. See, e.g., Moser v. U.S. Steel Corp., 676 S.W.2d 99 (Tex. 1984). 17. Getty Oil Co. v. Jones, 470 S.W.2d 618 (Tex. 1971). 18. Key Operating & Equip., Inc., 2013 WL 103633. 19. Gerrity Oil & Gas Corp. v. Magness, 946 P.2d 913, 927 (Colo. 1997); COLO. REV. STAT. § 34-60-127. 20. See, e.g., Kysar v. Amoco Prod. Co., 93 P.3d 1272, 1283 (N.M. 2004). 21. See, e.g., Anschutz Exploration Corp. v. Town of Dryden, 35 Misc. 3d 450 (N.Y. Sup. Ct. Feb. 21, 2012), aff’d sub nom. Norse Energy Corp. USA v. Town of Dryden, 108 A.D.3d 25 (N.Y. App. Div., 3d Judicial Dept. May 2, 2013); Cooperstown Holstein Corp. v. Town of Middlefield, 35 Misc. 3d 767 (N.Y. Sup. Ct. 2013) (holding zoning ordinance effectively banning oil and gas operations within township was not preempted by the New York State Environmental Conservation Law, which expressly superseded all

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local laws “relating to the regulation of oil, gas, and solution mining industries,” and stating “the state maintains control over the ‘how’ of such procedures, while the municipalities maintain the control over the ‘where’ of such exploration”). 22. See, e.g., Colorado Mining Ass’n v. Bd. of Cnty. Comm’rs of Summit Cnty., 199 P.3d 718, 730 (Colo. 2009) (holding Summit County’s ban on the use of cyanide or other toxic/acidic ore-processing reagents in heap or vat leach applications exceeded its statutory authority and was preempted by Colorado’s Mined Land Reclamation Act). 23. See, e.g., N.D. Cent. Code § 38-11.1-04 (requiring the mineral developer to “pay the surface owner a sum of money equal to the amount of damages sustained by the surface owner and the surface owner’s tenant, if any, for lost land value, lost use of and access to the surface owner’s land, and lost value of improvements caused by drilling operations.”); Mont. Code § 82-10-505 (“The oil and gas developer or operator is responsible for damages to real or personal property caused by oil and gas operations and production.”); OKLA. STAT. tit. 52 § 318.5 (requiring the operator to negotiate with the surface owner “for the payment of any damages which may be caused by the drilling operation” prior to entering the site with “heavy equipment.”). 24. Habendum is Latin for “that must be had.” 25. Pack v. Santa Fe Minerals, 869 P.2d 333 (Okla. 1994). 155

26. Clifton v. Koontz, 325 S.W. 2d 684 (Tex. 1959). 27. See, e.g., LOWE, supra note 4, at 202. 28. This is an example of a clause commonly found in many “producer’s 88” leases. 29. See, e.g., CORNELL UNIVERSITY COOPERATIVE EXTENSION, GAS EXPLORATION AND LEASING ON PRIVATE LAND: TIPS AND GUIDANCE FOR NEW YORK LANDOWNERS (July 2008). 30. Id. 31. See, e.g., Scott Lansdown, The Implied Marketing Covenant in Oil and Gas Leases: The Producer’s Perspective, 31 ST. MARY’S L.J. 297, 311–12 (2000). 32. See, e.g., Tex. Oil and Gas Corp. v. Vela, 429 S.W. 2d 866 (Tex. 1968) (holding “market value” determined by comparable sales or, if comparable sales are unavailable, by working back from downstream sales to the wellhead value; Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368 (Tex. 2001) (evidence of price in longterm gas purchase contract inadmissible to establish market value). 33. See, e.g., Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984). 34. See, e.g., Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994).

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35. Anderson, supra note 3, at II(D)(8)(b). 36. See also Rachel L. Allen & Scotland M. Duncan, The Standard Oil and Gas Lease—and Why It Is Not, 13 DUQ. BUS. L. J. 155 (2011). 37. See, e.g., Lenape Resources Corp. v. Tennessee Gas Pipeline Co., 925 S.W.2d 565, 572 (Tex. 1996). 38. See, e.g., Whitham Farms, LLC v. City of Longmont, 97 P.3d 135, 137 (Colo. App. 2003) (confirming that the lessor has the burden to prove breach of implied covenants.). 39. See, e.g., HECI Exploration Co. v. Neel, 982 S.W.2d 881, 887 (Tex. 1998). 40. See Lansdown, supra note 31. 41. For additional information, see Angela C. Cupas, The Not-So-Safe Drinking Water Act: Why We Must Regulate Hydraulic Fracturing at the Federal Level, 33 WM. & MARY ENVTL. L. & POLICY REV. 605, 606 (2009); Hannah Wiseman, Untested Waters: The Rise of Hydraulic Fracturing in Oil and Gas Production and the Need to Revisit Regulation, 20 FORDHAM ENVTL. L. REV. 115, 121 (2009). 42. W. VA. DEP’T OF ENVTL. PROT., INDUSTRY GUIDANCE: GAS WELL DRILLING/COMPLETION: LARGE WATER VOLUME FRACTURE TREATMENTS (Jan. 8, 2010) (“Hauling large volumes of water [for hydraulic

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fracturing] will result in significantly increased truck traffic that may create safety concerns, road damage, dust problems and other environmental issues.”), available at http://www.dep.wv.gov/oil-and-gas/GI/ Documents/ Marcellus%20Guidance%201-8-10%20Final.pdf. 43. See, e.g., 2 COLO. CODE REGS. 404-1 (requiring the disclosure of hydraulic fracturing fluid chemicals through the “FracFocus” website, at fracfocus.org). 44. See Elisabeth N. Radow, Homeowners and Gas Drilling Leases: Boon or Bust?, N.Y. ST. B.J., Nov.–Dec. 2011, at 10 (for a good discussion of other risks inherent in hydraulic fracturing operations). 45. Colorado’s, for example, slightly expands the common law doctrine by requiring that the operator select “alternative locations for wells, roads, pipelines, or production facilities, or [employ] alternative means of operation, that prevent, reduce, or mitigate the impacts of the oil and gas operations on the surface, where such alternatives are technologically sound, economically practicable, and reasonably available to the operator.” COLO. REV. STAT. § 34-60-127. 46. North Dakota and Montana, for example, require the developer to compensate the surface owner for surface use and damage. N.D. CENT. CODE § 38-11.1 et seq.; MONT. CODE ANN. § 82-10-501.

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4 Oil and Gas Exploration without Leases Rule of Capture and Compulsory Integration (Forced Pooling) in New York State Christopher Denton INTRODUCTION

This

chapter addresses the most common legal consequences to a mineral rights owner when the owner does not wish to lease his or her mineral rights or cannot come to an agreement with an oil and gas company about the terms and provisions of a lease. We will use New York State as a case study for the Northeast. The purpose of the chapter is to introduce the inexperienced reader, whether a lawyer, planner, municipal official, or environmental scientist, to one state’s recent attempt to overcome the historical, adverse consequences wrought by the Rule of Capture untempered by legislative intervention. It is not intended for the experienced oil and gas lawyer. The chapter begins by offering a simplified history of oil and gas ownership law, followed by a brief discussion

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of how the course of that law led to the enactment of Compulsory Integration under title 9 of Article 23 of the New York Environmental Conservation Law (ECL). The last portion of the chapter offers a brief explanation of how Compulsory Integration functions in New York. Most people are surprised to learn that if a mineral rights owner refuses to lease or develop his or her land for oil and gas, an oil and gas company may lease from the owner’s neighbors. By doing so, the company may take possession of the oil and gas without the owner’s permission. Additionally, the gas company may be able to keep up to 87.5 percent of the owner’s oil and gas, or may instead be able keep so much oil and gas as guarantees that the company recovers all of its drilling and development costs plus a profit of 200 percent, albeit prorated to the landowner’s acreage.1 Whether this is fair to all parties and whether this is constitutional are not the concern of this chapter. We leave those discussions to other writers in other forums. Our purpose here is to write about what exists now. The process by which an oil and gas company can legally take a landowner’s oil and gas without permission began with the judicial “rule of capture” and has been augmented over time with the addition of statutory provisions known as “compulsory integration” (sometimes known as “forced pooling”). ORIGINS OF THE RULE OF CAPTURE

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To understand the Rule of Capture and Compulsory Integration, we need to briefly review the evolution of the law governing the ownership of oil and gas in the United States. In most states, the Rule of Capture governs oil and gas ownership and has generally been defined by judicial decisions and not by statutes. Most non-lawyers are surprised that a whole body of law defining the ownership of oil and gas could be created by judicial decisions (called common law) without any input from a legislature. It is important to note, however, that if a legislature passes statutes modifying judicial decisions and then later repeals those statutes, the original judicial decisions become controlling law again. The judicial Rule of Capture arose from the fact that oil and gas flow under ground and geology as we know it today was not well understood at the time that judges were first asked by disputing landowners to decide who owned the gas and oil beneath their respective parcels. These problems of ownership first became evident when landowners discovered that if each of them drilled wells on adjacent land, the production from the first well would immediately decline at the moment production commenced on the neighbor’s well. The wells were said to be “communicating,” i.e., gas and oil were migrating underground. For non-lawyers, the question of ownership of minerals would seem apparent. In states where the federal or state government does not own the mineral rights and in the absence of the severance of mineral rights from the fee estate, whoever owns the fee estate (land) owns the minerals directly under the surface. This seemingly self161

evident assertion holds true for gypsum, limestone, or bluestone, for instance. It does not hold true for oil and gas, which tend to flow underground. The question of oil and gas ownership, therefore, reduces itself to a single basic question: who owns a natural resource that does not stay in one place, or in other words, tends to flow to the nearest well bore? Using hunting and game law as an analogy, the courts settled on a Rule of Capture. Courts ruled that oil and gas were fugitive and therefore were not owned until captured, much like a wild deer running across a farmer’s land. If the farmer shot it on his or her land, the deer belonged to the farmer. But if the deer left the farmer’s land unharmed, the farmer had no right to shoot it on the land of another without the other landowner’s permission. Therefore, a landowner who drilled the well on his or her own land had the right to keep anything that came out of the well. By capturing it, he or she gained ownership of it. As such, some courts have decided that a landowner only owns the gas and oil when he or she takes possession of it at the surface. Other states have alternatively held that one may actually own the oil and gas in the ground, subject to defeasance (loss of ownership) by someone lawfully draining it on his or her own land. In New York, the Rule of Capture specifically states that each landowner who owns land with the mineral rights intact has the right to own so much of the oil and gas as he or she actually takes from the ground. Accompanying this principle is the principle that the landowner has the right to access oil and gas by drilling on his or her own property. Until the oil and gas is 162

removed from the ground and reduced to actual physical possession above ground, the permanency of the ownership of the oil and gas will not have been established. In other words, if your neighbor drills a well on his or her property and in taking the oil and gas from that property drains the oil and gas from your property, the neighbor becomes the owner of all the oil and gas that comes out of his or her well, regardless of its source. The neighbor has no responsibility to pay you for it. The neighbor is not taking your oil and gas. The neighbor is simply exercising his or her rights to drain the pool of oil and gas that lies beneath the surface. CONSEQUENCES OF THE APPLICATION OF THE RULE OF CAPTURE The consequences of the Rule of Capture include the incentive to drill an excessive number of wells along the borders of the landowner’s property in order to prevent drainage by the neighbor and a rush to produce as much oil or gas as possible in the shortest time. This was common in the past because, unlike the present, landowners once had the right to drill innumerable wells on their property, regardless of the size of the property. Under an unmodified Rule of Capture, landowners were compelled by economics to drill as many wells as possible on their land and to drill them as close to their boundary lines as possible to prevent the neighbor from legally capturing all the gas and oil in the common pool. Drainage by a neighbor was therefore a point of serious economic concern.2 These drilling incentives caused by the Rule of Capture also resulted in severe overproduction, which resulted in a glut of oil and gas on 163

the market. This in turn caused massive swings in prices, which produced boom and bust years.3 The right to protect the oil and gas beneath the surface of landowners’ property was substantially influenced by their economic means. If they had the money to drill, they could protect their oil and gas by drilling wells to drain as much as the wells would allow. If they had no money, then the neighbor’s wells would instead drain the gas and oil pool beneath the property. Regardless of their financial capacity, however, landowners always had the right to drill on their own property. Ironically, too many wells on too little space resulted in a second kind of economic loss—the loss of well bore pressure that caused much oil to be trapped in the ground, unrecoverable. This loss was considered “wasteful” and became one of the prime rationales for subsequent laws enacting unitization and well spacing rules. Although the Rule of Capture essentially leaves landowners with the right to drill and remove oil and gas, it also required that the well and the well bore be located exclusively on landowners’ property. Landowners could not legally drill under a neighbor’s property without the neighbor’s permission. Such drilling would constitute a trespass. In the highly technical age in which we live and with the rise of geology, geophysics, geochemistry, and highly efficient drilling techniques, the issue of trespass was sure to arise. In Texas, the supreme court was asked to decide whether the fracturing of a well that causes the fractures to extend on to the neighbor’s property is a trespass.4 The court decided that, for Texas, the Rule of Capture is so 164

strong that when the hydraulic fractures extend into another owner’s property, the owner may not be able to legally recover damages for the gas drainage caused by such fractures. The issue concerned lines of fracture, not the well bore. A well bore entering a neighbor’s land without his or her consent would still constitute a trespass. As recently as April 2013, a West Virginia federal district court disagreed, stating “that hydraulic fracturing under the land of a neighboring property without that party’s consent is not protected by the ‘rule of capture,’ but rather constitutes an actionable trespass.”5 SOLUTIONS TO THE ADVERSE ECONOMIC CONSEQUENCES OF THE RULE OF CAPTURE The oil and gas industry for its first fifty years of life either boomed with great profit or busted horribly with many operators bankrupted. After another round of losses in the Depression and to alleviate the wild market fluctuations in the price of oil and gas and to stabilize production, several producing states agreed to form the Interstate Oil and Gas Compact Commission, (initially founded as the Interstate Oil Compact Commission). Although this body has no enforcement power, it has been said that it is “the most powerful powerless organization in the world.”6 The member states, in an attempt to rein in these destructive swings in the market and to prevent the waste of oil and gas caused by excessive drilling, instituted a number of reforms. These included setting distances between wells (spacing to prevent communication and 165

drainage), establishing units (in order to determine correlative rights), limiting the number of wells in the unit (to prevent waste of capital and product), forcing “unleased” mineral owners into a single unit for drilling purposes (to prevent landowners from holding out), and above all, requiring that no well be drilled without first obtaining a permit. These measures helped to stabilize the economics of oil and gas. Thus Compulsory Integration must be viewed from the larger perspective of market stabilization, statewide spacing, unitization, and correlative rights guarantees. Our case study state, New York, also eventually signed the Interstate Oil and Gas Compact.7 Embracing the policies promoted therein, New York State in section 301 of the ECL set forth the following statement of the purposes of its Oil and Gas Policy: “To regulate the development, production, and utilization of natural resources of oil and gas in this state in such a manner as will prevent waste; to authorize and to provide for the operation and development of oil and gas properties in such a manner that a greater ultimate recovery of oil and gas may be had; and that the correlative rights of all owners and the rights of all persons including landowners and the general public may be fully protected.”8Among these policies, the ones that lead most inevitably to compulsory integration are the policies toward “a greater ultimate recovery of oil and gas” and the full protection of correlative rights. The correlative rights guaranteed in the ECL are essential to the notion of Compulsory Integration and can be stated two ways: (1) “an owner who exercises the right 166

to capture oil and gas is subject to the concomitant duty to exercise the right without negligence or waste”; and from a more positive perspective, (2) “the correlative-rights doctrine provides that each owner of minerals in a common source of supply has the right to a fair chance to produce oil and gas from the reservoir substantially in the proportion that the quantity of recoverable oil and gas under his or her land bears to the quantity in the reservoir.”9 Once correlative rights had been recognized by judges and in policy statements, it followed that the legislature would enact a compulsory integration statute. INTRODUCTION TO COMPULSORY INTEGRATION IN NEW YORK STATE The statute regulating oil and gas development in New York State is Article 23 of the ECL, entitled the Oil, Gas, and Solution Mining Law, and it is administered by the New York State Department of Environmental Conservation (DEC). Permitting and statewide well spacing proceed under Title 5, voluntary integration and unitization under Title 7, and compulsory integration and correlative rights under Title 9. Well spacing in New York is determined by the targeted formation and the depth drilled. Although New York has chosen a multifaceted approach, this chapter will concentrate only on Title 9 and Compulsory Integration. As currently enacted, Article 23 section 0901 of the ECL attempts to establish a system that will allow a driller/operator to drain an entire unit without the permission of every landowner in it, while attempting to protect an unleased landowner’s correlative rights by 167

offering three different forms of compensation for the loss of the rights to drill, to take and keep oil and gas, to prevent drainage, to decide when a well will be drilled on the owner’s property, and to determine the competence of a well driller, i.e., to decide by whom and how a well will be drilled. The statute attempts to accomplish these goals of orderly development, non-wasteful drilling, and the prorata distribution of oil and gas production by first requiring that a single permit be issued and that a spacing unit be formed, all prior to drilling. Enormous amounts of capital are preserved by these requirements. Under current law, no wells need to be drilled along a boundary line. One well, properly located, can drain the entire unit. To qualify for a permit, the driller must control by ownership or lease at least 60 percent of the acreage included in the unit. The permit will be limited to the one unit, to the one depth, and to the one target formation named in the application. Any landowner/mineral rights owner who is in the unit and who is not “controlled” by the driller/ operator must then be Compulsorily Integrated by the driller/operator under the proceeding set forth in Title 9 of the ECL. The unit is formed and the mineral rights owners are identified in the application for the permit. The driller is permitted to commence drilling as soon as the permit has been issued and the unit map approved but cannot drill under any unleased or “uncontrolled” property until a Final Order of Integration has been issued by DEC. If the well is successful, the driller/operator can commence 168

production immediately, not having to pay the unleased landowners until the Final Order of Integration is issued, which can be years away. COMPENSATING A LANDOWNER COMPULSORY INTEGRATION

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How is a landowner compensated under involuntary integration? Without identifying for which losses the landowner will be compensated nor allocating the compensation for those losses, Title 9 of the Article 23 of the ECL sets forth three exclusive classes that may provide compensation to the landowner, but the owner must choose among them within 21 days of receiving notice of the Compulsory Integration Hearing. They are (1) the Integrated Royalty Owner, (2) the Integrated NonParticipating Owner, and (3) the Integrated Participating Owner. Of the three, the Integrated Royalty Owner is the default status. If the landowner does nothing or ignores the proceeding, the statute designates him or her as an Integrated Royalty Owner. A landowner who has the financial wherewithal and can access it within thirty days of receiving the notice of the Compulsory Integration Hearing can “participate” in the well as an Integrated Participating Owner (IPO). This means that he or she will contribute a prorata share of the capital costs of that well (as shown in the document called an Authorization For Expenditure, AFE). The owner will assume proportionate liability in contract and tort and will be obligated to contribute more funds when additional capital is needed for the well. In other words, the owner can engage in a high-stakes poker game for which he or 169

she has had no reasonable time to raise the necessary funds (which has unlimited raises), for which he or she has enormous liability beyond the capital costs, and in which he or she has no voice in any decisions whatsoever. The upside is that from the first day of production the owner is entitled to a proportionate share of the profits. The down side is self-evident—the loss of the owner’s entire investment. A landowner who does not have access to such funds can elect to become an Integrated Non-Participating Owner (INPO). With this election he or she does not need to advance any funds whatsoever. However, the production profits that are attributable to the owner’s portion of the unit are subject to a “risk penalty.” The statute does not define the risk penalty nor explain its rationale. It does, however, clearly state the amount of the penalty as 300 percent of the costs of the well, prorated to the landowner’s acreage in the unit. Furthermore, the INPO is not entitled to a prorata portion of the production profit until the 300 percent has been entirely recovered by the driller/operator from the well’s production. In effect, this means that the well operator is entitled to a guaranteed recovery of all of the landowner’s prorated well costs plus a 200 percent prorated profit. Yet this doesn’t tell the whole story. Another way to view the driller’s benefit is to calculate the driller’s profit in those circumstances where the driller holds leases for the bare minimum—60 percent of the acreage of the unit. If all the “uncontrolled landowners” elected Integrated Non-Participating Owner status, the driller would recover 120 percent (i.e., 40 percent × 300 percent) of the full cost 170

of the well, regardless of any proration of the costs to those landowners. In other words, the uncontrolled landowners would be paying 120 percent the entire costs of the well, not just their prorata portion. If the well produces marketable oil or gas of sufficient value, the driller/operator could literally drill and complete the well without any cost to it. This raises the question of whether there is any incentive remaining for the driller/operator to continue to acquire leases once it has achieved the 60 percent ratio. It is likewise possible that the INPO will never receive a cent for the loss of his or her right to drill or to prevent drainage, the loss of his or her rights to the oil and gas, the loss of his or her right to decide when or how to drill, and the loss of time needed to obtain investors to drill. In other words, because of the statute, the driller/operator could end up with all the landowner’s gas or oil for free, and without having to pay for any of the well costs. There is a final irony. If the well bore travels under the uncontrolled landowner’s land pursuant to the permission granted in the Final Integration Order, then the landowner will not be paid for that permanent invasion of his or her subsurface rights. Yet if the same oil and gas company tried to construct a gas-gathering pipeline beneath the surface of the same landowner’s property, it would be a trespass unless the company had the power of eminent domain and paid the fair market value for the pipeline easement. The third statutory election is the Integrated Royalty Owner (IRO). If the landowner ignores the proceeding, he 171

or she is deemed an IRO and gets the lowest royalty of all the leases in the unit, but not less than 12.5 percent. DEC has ruled in administrative hearings that the royalty is calculated without deducting any costs. The statute also specifically insulates the IRO from any liability related to the well and denies the driller any use of the surface of the IRO’s property. We take special note that at the end of Title 9, the statute contains a provision that saddles the buyer of a compulsorily integrated real property with the election of the previous owner, including the liabilities thereunder. The provision states, “Any person taking title by operation of law to any oil and gas interests integrated into a spacing unit pursuant to an order of integration, shall take such interests subject to the terms and conditions of the final order of integration issued by the department duly recorded in accordance with the provisions of this section and shall be subject to all liabilities and benefits associated therewith, unless such person, within sixty days of the taking of such interest, elects to be an integrated royalty owner and notifies the well operator of such decision.”10 When the Compulsory Integration Proceeding actually commences, the driller/operator must give 30 days’ actual notice to any unleased landowner in the unit. The hearings are held exclusively in Albany, NY, and the unleased landowner has only 21 days to file his or her election with DEC or be deemed an IRO. It has been the practice of oil and gas investors who have acquired leases, and thereafter find themselves compulsorily integrated, to request and litigate 172

detailed modifications and amendments to the Integration Order on the grounds that the statute requires that the integration order be “upon such terms and conditions that are just and reasonable.”11 There is a quirk in Title 9 that states that if you are a lessee when the integration hearing is held and if you elect the Integrated Non-Participating Owner status, then you, as lessee, are entitled to a special graduated royalty interest in the well until the 300 percent risk penalty has been paid in full from the landowner’s portion of the production proceeds. This loophole was written for the industry, which sometimes holds leases but not the permit. The loophole would give those companies some extra money. Normally the INPO receives no proceeds until the risk penalty has been paid in full. But if the landowner forms a Limited Liability Company (LLC) wholly owned by the landowner, he can then lease to his or her own LLC. The LLC thereby qualifies as a lessee and receives the graduated royalty during the risk penalty phase. DEC administrative law judges have upheld this practice by INPOs. There is a fifth option that has grown out of a unique practice of some landowner attorneys, which is unofficially called the Compulsory Integration Lease. Once the unleased landowner is notified of the Compulsory Integration hearing, he or she is often approached by investor companies who want “into the game” by leasing from the owner. If the investors have oil and gas leases in a unit but not enough leases to qualify to be the permit holder, then they will be integrated by the permit holder and can themselves elect to be a 173

“participating owner,” i.e., a partner. Like any other IPO, they must front all the money immediately (at the hearing). The driller cannot refuse to take them as an IPO, and the investors will receive their net profits from the first day of production (see figure on opposite page). In the Compulsory Integration Lease model, the landowner only leases the target formation to which the permit has been granted, leases no surface rights, and usually receives no bonus. The lease lasts only the duration of the permit and covers only the acreage included in the unit. It is specific to the permit, the unit, and the target formation. It is an unusual compromise by a landowner and a company that has been competing with the permit holder. The typical royalty of this kind of lease is usually higher than the royalty of a landowner who signed a lease with the permit holder. This constitutes an easy shortcut for an investor to get into a well as a partner without the necessity of signing a Joint Operating Agreement with the permit holder. Moreover, an Integrated Participating Owner is entitled to well log data (the essential raw geologic data recorded during the drilling process), as well as production figures, etc. That data has value. Under New York law the public can be stopped from obtaining that information for up to two years, but not so for the IPO. He or she is entitled to it upon paying the upfront money.

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Outline of Statutory Unitization * Exception when the NPO is a lessee, then the NPO receives a graduated royalty: a. On production equaling 100% of the cost of the well—6.25% b. On production equaling the second 100% of the cost of the well—9.38% c. On production equaling the third 100% of the cost of the well—12.5%

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Non-Statutory Alternative: Lease to an investor only so much of the target formation as is included in the compulsory integration notice, for the life of the permit and the life of the unit, reserving all other formations and rights and granting no surface rights. In other words lease the same amount of mineral rights as are covered by the compulsory integration proceeding. This allows one to participate and still be able to lease the remainder of the rights to others. THE MATHEMATICS OF COMPULSORY INTEGRATION Here is how the math would work in New York for a typical Compulsory Integration Proceeding. Our figures and location are taken from an actual Authorization For Expenditure (AFE) and an actual Spacing Unit Map (Unit Map) in a completed Compulsory Integration Proceeding, but we shall use a fictitious landowner and a fictitious exploration and production company. Act I: Ms. Carey Drake and her husband, Grant Drake, own 100 acres of land. They have not leased their land to anyone. The permit holder is E&P Resources, Inc. (E&P) of Tulsa, Oklahoma, which has obtained leases from everyone around the Drakes. The lowest royalty rate in the leases is 12.5 percent. E&P filed an application showing the Spacing Unit Map of 160 acres and that the Drakes were not 176

“controlled.” DEC issued the permit and ordered E&P (now called the operator) to commence a Compulsory Integration hearing. The Notice of Hearing was served in person upon both Drakes along with an AFE and an Election Form, the template for which is located on the website of DEC. E&P has already started to drill. 14.38 acres of the Drake’s land have been included in the Weston #1 well, API # 31-107-73406-00-00. (Wells are often named after the landowner on whose land they are located.) The API number can be read as follows: the first two digits identify the state, the second two digits identify the county, the next five-digit group is the unique well number, the next two digits identify the number of sidetracks, and the last two digits indicate the number of operations had on a single well bore. The Drakes own 8.9875 percent of the acreage in the well.

14.38 acres / 160 acres = 8.9875% of the acreage

In the first year the well produces gross sales of $1,000,000.00 from the sale of natural gas from the Weston #1 well.

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The AFE is $344,474.99. This constitutes the projected cost of all the drilling and completion. The prorated costs to the landowner is $344,475.00 × 8.9875% = $30,959.69, which is the amount that the landowner as IPO would have to pay at or before the Compulsory Integration Hearing. Act II: A. The Drakes have 21 calendar days from receipt of the Notice of Hearing to file an election on the Election Form supplied by E&P. If the Drakes do nothing, they will become an Integrated Royalty Owner at 12.5 percent without any deductions for any costs of transportation or preparation for market. They will have no liability for any matters arising out of the permit and the election. Their return at the end of the first year will be 12.5% royalty × (8.9875% of the acreage × $1,000,000.00 gross sales for the unit) = $11,234.375. If the well is a “duster,” there is no loss as the Drakes paid in no money. B. The Drakes can pay to E&P the sum of $30,959.69 (their prorata share of drilling and completion costs) before the end of the hearing by certified funds to become an Integrated Participating Owner. By doing so the Drakes must now pay more money to E&P each and every time the costs of the Weston #1 well exceeds the AFE and all funds collected thereafter. If the Drakes do not pay, then they will lose all the money they have paid, and they will be involuntarily converted to an IRO with 178

no way of recovering their investment. They will have “folded” in this high stakes poker game. If on the other hand they always make the payments demanded and on time and the well produces gas in paying quantities, the Drakes will receive 100 percent of the sales price of the gas attributable to their percentage of the acreage in the unit, less the costs of transportation, preparation, and operation of the well. The return on investment could be high. The losses could be crippling. Calculating returns based on first year’s sales of $1,000,000.00, the profit would be as follows:

($1,000,000.00 gross sales – 10% overhead $100,000.00) × 8.9875% of ac. 5 $80,887.50

at

Losses could be the full $30,959.69 plus any “calls” for more capital on a “dry hole.” C. The Drakes can elect the Integrated NonParticipating Owner and pay in nothing. They will not receive a penny until the well sales have achieved at least 3 × $344,475.00 or $1,033,425.00. In this circumstance, an INPO would receive nothing the first year, while the company received all of the INPO’s gas for free. If the Drakes had formed an LLC and had then leased to their own LLC before the election period expired, they

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would have achieved a graduated royalty return as follows:

On the first $344,475.00 of gross sales: ($344,475 × 6.25%) × 8.9875% = $1,934.98

On the second $344,475.00 of gross sales: ($344,475 × 9.38%) × 8.9875% = $2,904.02

On the third $344,475.00 of gross sales: ($311,050.00 × 12.5%) × 8.9875% = $3,494.45

Totaling: $8,333.45 in graduated royalties

Once the 300 percent penalty has been paid then the INPO effectively becomes an IPO. D. Once the final compulsory integration order is issued, the landowner or his or her successor remains in the unit and bound by the order until the permit is surrendered or revoked. CONCLUSION

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The benefits and liabilities of compulsory integration vary in risk and reward. But in the end, Compulsory Integration, Forced Pooling, Drainage Protection, Spacing Rules, Correlative Rights, and Unitization come into existence because of the economic pressures on mineral rights owners from the application of the Rule of Capture. As long as the Rule of Capture is the controlling principle of oil and gas ownership, there will be a need for some modifying influences to ameliorate the irrational and wasteful habits generated by the economics of its raw application. As a consequence, repealing, amending, or modifying any or all of these concepts will have a direct impact on the rights of mineral owners and on the economics of oil and gas development. The advisability or merits of repealing or altering these legal concepts is reserved for another forum. NOTES 1. N.Y. ENVTL. CONSERV. LAW § 23-0901. 2. TERENCE DAINTITH, FINDERS KEEPERS?: HOW THE LAW OF CAPTURE SHAPED THE WORLD OIL INDUSTRY (2010). The historical background set forth in this chapter is derived from N.Y. ENVTL. CONSERV. LAW § 23-0901 and from DANIEL YERGIN, THE PRIZE: THE EPIC QUEST FOR OIL, MONEY AND POWER (2008). 3. Daintith, supra note 2.

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4. Coastal Oil and Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1 (Tex. 2008). 5.

Stone v. Chesapeake Appalachia, LLC, No. 5:12-cv-102, at 16 (N.D. W. Va. Apr. 10, 2013) (order denying defendant’s motion for summary judgment).

6. DAINTITH, supra note 2, at 376. 7. N.Y. ENVTL. CONSERV. LAW art. 23, tit. 21, § 2101. 8. N.Y. ENVTL. CONSERV. LAW art. 23, tit. 3, § 0301. 9. JOHN S. LOWE, OIL AND GAS LAW 15–16 (5th ed. 2003). 10. N.Y. ENVTL. CONSERV. LAW art. 23, tit. 9, § 0901(13). 11. Id. § 0901(3).

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5 Getting Gas to the People The Federal Energy Regulatory Commission’s Permitting Process for Pipeline Infrastructure Suedeen Kelly and Vera Callahan Neinast

Natural gas is a gaseous hydrocarbon mixture consisting primarily of methane. Unlike oil, which comes out of the ground in a liquid form that can be easily transported by truck, rail or pipeline, natural gas (in its gaseous form)1 can only be transported by pipeline. Therefore, getting natural gas from the wellhead to the ultimate consumer requires a great deal of infrastructure. The recent surge in natural gas production from shale gas formations has resulted in a boom in pipeline construction. That is because many shale gas formations are located in areas that do not have an established pipeline infrastructure, such as North Dakota, or in areas where the existing pipeline infrastructure does not have sufficient capacity to accommodate the increased production. Where pipeline infrastructure is insufficient or nonexistent, oil well producers may simply burn, or “flare,” gas that is produced with oil. Flaring gas wastes an otherwise valuable resource. This chapter explores the types of infrastructure necessary to transport natural gas to its ultimate destination and describes the regulatory

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framework applicable to each phase of movement—production, gathering, transmission, distribution, and storage. Additionally, the chapter will discuss how concerned members of the public can obtain information about and become involved in the pipeline construction approval process. OVERVIEW The natural gas industry is highly regulated, with different aspects regulated by the states and the federal government. The states regulate the production of gas. A producer must obtain a permit from the applicable state agency to drill and operate wells. Once the natural gas comes to the surface, it is moved through a series of pipelines, which are subject to different regulatory regimes. Gas is first transported from the well via small production pipelines. The production pipelines take the gas to larger gathering pipelines. Gathering pipelines gather gas from a number of wells and generally transport the gas to a processing plant where it is processed to pipeline quality and then delivered to a high-pressure transmission pipeline. Processing plants remove liquefiable hydrocarbons (ethane, butane, propane, pentanes, and other heavier hydrocarbons) from the natural gas, and impurities such as water, carbon dioxide, hydrogen sulfide, or nitrogen. The purpose of processing is to make the gas suitable for industrial and residential use and to separate out heavier hydrocarbons that can be sold as separate products. If processing is not required (for example, if the gas is “dry” gas containing few hydrocarbons or impurities), the gathering pipeline may 184

deliver the gas directly to a transmission line or to a local distribution company. The transmission pipeline moves the gas directly to customers (typically industrial customers) or to local distribution companies, which then deliver gas to residential, commercial, and industrial customers for ultimate consumption. It may be helpful to visualize the pipeline system by comparing it to a road system—which, in a sense, it is. The gas leaves its house (the well) and travels along a driveway (production line) to the street (gathering line). The street feeds into a larger street or highway (transmission line), which takes the gas across the state or across the country to another town. At that point, the gas leaves the highway (transmission line) and enters a smaller road system (local distribution company), which then delivers the gas to its destination: residential, commercial, or industrial consumers. Similar to a road network, there are quantitatively more smaller production, gathering, and distribution pipelines than there are larger transmission lines. Regulatory oversight over pipelines is based on the function performed by the particular pipeline. Production lines, gathering lines, transmission lines, and distribution lines are all subject to different regulatory requirements. THE NATURAL GAS ACT OF 1938 Natural gas has been moved by pipeline in the United States since the mid-1800s. In the early days, pipelines were relatively short, delivering natural gas in the vicinity 185

of its production. These pipelines were regulated by local governments, which realized that without regulation, pipelines as “natural monopolies” could exert market power to charge high rates. By the early 1900s, advances in technology enabled the construction of pipelines that could carry natural gas long distances. After a series of U.S. Supreme Court decisions determined that local government regulation of interstate pipelines would violate the commerce clause of the U.S. Constitution, Congress passed the Natural Gas Act, or NGA, in 1938 to provide for federal regulation of interstate pipelines. Section 1(b) of the NGA sets forth the scope of federal regulation, which applies to (1) the transportation of natural gas in interstate commerce, (2) the sale in interstate commerce of natural gas for resale, (3) natural gas companies engaged in such interstate transportation or sales, and (4) the importation or exportation of natural gas in foreign commerce and to persons engaged in such importation or exportation. Section 1(b) specifically exempts from federal regulation “any other transportation or sale of natural gas or … the local distribution of natural gas or … the facilities used for such distribution or … the production or gathering of natural gas.”2 As a result of the NGA, the federal government regulates interstate transportation of natural gas, while the regulation of production, gathering, intrastate transportation, and local distribution of gas is left to the states. The primary federal agency charged with administration of the NGA is the Federal Energy Regulatory Commission, or FERC, which is an independent agency under the Department of Energy 186

umbrella.3 While it may appear that the jurisdictional boundaries between federal and state regulation are clear cut, in fact they are not, because the NGA does not define the terms “production,” “gathering,” “transportation,” or “local distribution.” WHAT TYPES OF PIPELINES ARE THERE, AND HOW ARE THEY REGULATED? Production Pipelines Although the NGA does not define the term “production,” the industry has developed general guidelines for determining what constitutes a production pipeline. These guidelines are set forth in the American Petroleum Institute’s Recommended Practice 80,4 or API RP 80. According to API RP 80, production pipelines are generally considered to be those pipelines that relate to the extraction and recovery of natural gas, and may include individual well flowlines, equipment piping, transfer lines between production operation equipment elements and sites, and tie-in lines to connect to other pipelines, such as gathering, transmission, or distribution pipelines.5 Production pipelines are not regulated by FERC and are not subject to federal pipeline safety requirements.6 Production pipelines are subject to state regulation, but most states impose minimal, if any, regulatory requirements on production pipelines. Gathering Pipelines

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If natural gas crosses a state boundary in its journey from wellhead to consumer (even if this journey takes place on multiple pipelines, some of which may not cross state lines), then federal jurisdiction generally attaches to all of the facilities used for the transportation of such gas and to all of the companies engaged in such transportation. However, natural gas may be gathered across state lines without federal jurisdiction attaching to the gathering facilities, because the FERC has no jurisdiction over the gathering of natural gas under the NGA.7 FERC jurisdiction attaches once gathering stops and transportation begins.8 Thus, it is important to understand how the distinction is made between gathering and transportation (transmission) pipelines. Because the terms gathering and transportation are not defined in the NGA, the FERC has developed several legal tests over the years to determine which facilities should be deemed to be non-jurisdictional gathering facilities and which facilities should be considered to be jurisdictional transmission facilities. The FERC currently relies on the modified “primary function test” to delineate between gathering and transportation.9 This test considers six physical and geographic factors, including: (1) the length and diameter of the pipelines, (2) the extension of the facility beyond the central point in the field, (3) the facility’s geographic configuration, (4) the location of compressors and processing plants, (5) the location of the wells along all or part of the facility, and (6) the operating pressure of the pipelines. In addition, the FERC also considers the purpose, location, and operation of the facilities; the general business activity of the owner of the facilities; and whether the jurisdictional determination is 188

consistent with the NGA and the Natural Gas Policy Act. The FERC does not consider any one factor to be determinative and recognizes that all factors do not necessarily apply to all situations. In short, the FERC’s modified primary function test is a subjective test. Until the FERC scrutinizes specific facilities under this test, the actual jurisdictional status of a particular pipeline cannot be definitively determined. As a rule of thumb, it is generally accepted that pipelines upstream of a processing plant are considered to be engaged in the gathering of gas.10 If there is no processing plant in the field, then it is less predictable where the FERC would place the point of demarcation between the gathering and the transportation functions on a particular pipeline system. States generally apply light-handed regulation to gas gathering pipelines, unless such pipelines are regulated as gas utilities, in which case service obligations and rate oversight may apply. Construction authorization is generally not required. Transmission Pipelines Once gathering has ended, then transportation or local distribution begins. Transmission pipelines generally are high-pressure, large-diameter pipelines that transport natural gas long distances. These pipelines are typically 24 to 42 inches in diameter and may operate at pressures in excess of 1000 pounds per square inch. The large size and high pressure is necessary to move large quantities of natural gas efficiently. Compressor stations placed along the pipeline keep the gas pressurized and moving. The U.S. Energy Information Administration, or EIA, 189

estimates that the United States has more than 300,000 miles of interstate and intrastate transmission pipelines. If a transmission pipeline crosses a state line, then it is considered to be an interstate pipeline subject to FERC jurisdiction. However, even transmission pipelines that are wholly located in one state may become subject to FERC jurisdiction if they transport gas as part of a chain of movements in interstate commerce from the wellhead to the burner tip. Thus, if gas is produced and gathered in Texas and is delivered to an intrastate pipeline, which then delivers the gas to an interstate pipeline that delivers the gas to a customer in Louisiana, the Texas intrastate pipeline would be considered to be engaged in the interstate transportation of gas and subject to FERC jurisdiction.11 Local Distribution Pipelines Local distribution pipelines tend to be lower in pressure and smaller in diameter than transmission lines. A local distribution company is the local gas company or municipality that provides gas utility service to end users. A local distribution company typically receives gas from a transmission line and steps down the operating pressure to 200 pounds per square inch or less. By the time natural gas is delivered to a residence, the pressure has been reduced through regulators to less than one-quarter pound per square inch. These pipelines are not regulated by FERC, but are subject to varying degrees of state regulation. PHMSA estimates there are more than two million miles of gas distribution pipelines in the U.S.

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Storage Facilities Natural gas can be stored in underground caverns for later use. Most storage facilities are depleted natural gas or oil fields, but aquifers and salt caverns are also used to store natural gas. Many local distribution companies and other large gas users contract for gas storage to supplement their gas supplies during periods of high demand, such as very cold winter days or very hot summer days. Natural gas can also be stored as liquefied natural gas (LNG), by cooling it to approximately –260 degrees Fahrenheit. LNG is kept in specially built storage tanks. When it is needed for periods of peak demand, then the LNG is regasified and transported by pipeline where needed. A benefit of LNG storage is that it can be placed close to market areas, and is therefore valuable to ensure reliability of service during periods of peak demand. FERC considers storage to be a form of transportation. Thus, if a storage facility is used to store gas that has been or will be transported in interstate commerce, then the storage cavern and associated piping is likely to be subject to FERC regulation as an interstate pipeline facility.12 According to the EIA, there are currently approximately 400 active storage facilities in the continental United States, with about 200 of these subject to FERC regulation. Pennsylvania, West Virginia, and New York have the most FERC-jurisdictional storage facilities, with 40, 26, and 25, respectively. Intrastate storage facilities are subject to varying levels of state regulation.

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WHAT TYPE OF REGULATORY APPROVAL PROCESS IS REQUIRED TO CONSTRUCT A PIPELINE? The type of regulatory approval process that is required to construct a pipeline depends on the type of pipeline that is being constructed. Production, gathering, intrastate transmission, and local distribution company pipelines are subject to state regulatory requirements. Thus, most of the pipelines that will be constructed to support the shale gas boom will be subject to state regulatory oversight, which varies greatly from state to state. Some state commissions may require pipelines to obtain construction permits, while other state commissions simply require notification of construction, or have no requirements. Some states may regulate the construction of transmission pipelines, but not gathering pipelines. It is not possible to make any generalizations regarding state regulation. The best way to determine what a particular state’s requirements are is to visit the state regulatory agency’s website. Most state agency websites have links to the governing state statutes and their administrative rules, which would provide more detailed information. Unlike the states, the federal government has a wellestablished approval process for construction of interstate natural gas pipelines. Under the NGA, a pipeline must obtain prior approval from the FERC, called a “certificate of public convenience and necessity,” before construction may commence.13 Helpfully, the FERC issued a Statement of Policy in 199914 concerning certification of new interstate pipeline facilities that sets forth the principles applicable to the FERC’s review of interstate 192

pipeline certificate applications, including the overarching principle that the public benefits must outweigh the adverse effects of the proposed construction. The Statement of Policy and the FERC’s regulations provide the framework for FERC review of pipeline construction projects. The FERC Process The determination of need for new interstate pipeline facilities starts with the pipeline and its existing or potential customers. Gas producers or potential gas users may approach a pipeline to inquire whether the pipeline has sufficient existing capacity to transport additional gas supplies. Because of the lead time necessary to obtain construction permits, these communications typically occur before wells are drilled. Obviously, it does not make sense to drill a well and then not be able to move the gas to market. A pipeline company that receives expressions of interest will conduct an “open season” to determine whether there is a market need for additional pipeline infrastructure. The company publishes details about its proposed construction, and all interested customers have the opportunity to sign up for service. In addition to being required by FERC, the open season is useful for the pipeline’s planning purposes, as it enables the pipeline to adjust the scope of its project to meet the expected demand for pipeline capacity. For example, if there is greater demand than the pipeline had anticipated, the company may decide to construct a larger-diameter pipeline. Conversely, if there is less demand than anticipated, the pipeline may be able to meet the expected

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level of new demand by adding compression or looping the existing line, instead of laying a new line. Following the open season, the pipeline company selects its proposed pipeline route and meets with landowners along the route. The FERC encourages pipeline companies to secure easements and rights-of-way by negotiation with landowners. The pipeline company may also hold public meetings along the proposed pipeline route to educate the public about the proposed project at this stage. Pipeline companies have the option to utilize the FERC’s “prefiling” procedures for construction of new pipeline facilities (such procedures are mandatory for construction of liquefied natural gas terminal and related pipeline facilities). Under these procedures, the pipeline requests the FERC to open a prefiling docket. The prefiling process provides for a 180-day period for the pipeline, the public, and the FERC to hold scoping meetings and review information from the pipeline about the proposed pipeline project. As part of the prefiling process, the pipeline company files draft environmental resource reports, which are available for public review. The prefiling process is intended to be a vehicle for addressing and resolving public concerns about a proposed pipeline construction project before the formal FERC certificate application is filed. Less controversy and public outcry generally results in a quicker approval process once the formal application is filed.

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If the prefiling process is not used, then after the open season the pipeline company sets about assembling the information necessary to file a certificate application with the FERC. This includes information about the pipeline company, maps, flow diagrams, market data, information on costs and financing, and an environmental report, which is normally prepared by environmental consultants. The environmental report consists of 12 resource reports sufficient to meet the requirements of the National Environmental Policy Act (NEPA). The FERC will conduct an environmental study of the applicant’s proposed project and either prepare an Environmental Assessment (EA) for more minor projects, or an Environmental Impact Statement (EIS). Underground storage facility projects and major pipeline construction projects using rights-of-way in which there is no existing natural gas pipeline require the FERC to prepare an EIS. After the necessary information is assembled, the pipeline company files its application with the FERC. The FERC issues a notice of the application in the Federal Register shortly after the application is filed, usually within a week or two. The Federal Register notice provides information concerning the proposed construction project, identifies a contact person for the applicant, sets forth a projected timetable for the FERC’s environmental review, and provides information about how to file comments about the application or become a party to the proceeding. After the notice is issued, the pipeline is required to publish newspaper notice of the application, notify all affected landowners, towns, communities, and local, state, 195

and federal government agencies involved in the project, and provide such entities copies of the most recent version of the FERC’s pamphlet that explains the FERC’s certificate process.15 Next, the FERC conducts public scoping meetings to determine the extent of environmental issues related to the proposed project. The FERC reviews the application, and may request additional information from the applicant. The FERC may issue an order on the project’s nonenvironmental factors, such as rate design, before it completes its environmental review. The FERC then determines whether it needs to complete an EA or an EIS. When completed, a draft of the EA or EIS is sent to other federal agencies for their review and input. The FERC is the lead permitting agency for pipeline construction projects, but other federal agencies, such as the U.S. Environmental Protection Agency, the U.S. Fish and Wildlife Service, or the Army Corps of Engineers, may also have permitting authority over aspects of the project. Following their review, the FERC will issue a draft EIS or EA for public review and comment. If the FERC issues a draft EIS, the FERC will also hold meetings in the project area to take public comments on the draft. After the close of the public comment period, the FERC will respond to comments received and prepare a final EIS or EA. Following the issuance of the final EA or EIS, the FERC will issue an order either approving or denying the certificate application. Typically, the FERC order approving an application will require the applicant to comply with a number of conditions, including completion of the 196

construction within a set period of time, compliance with all FERC regulations, and compliance with environmental conditions listed in an appendix to the order. The environmental conditions will include a condition that the applicant submit proof to the FERC that it has secured all other required federal permits before construction may commence. HOW CAN THE PUBLIC EFFECTIVELY CONVEY CONCERNS ABOUT PROPOSED PIPELINE PROJECTS? The relatively recent discovery of shale gas and the rush to develop and produce this resource means that a large network of new pipeline infrastructure will be needed to gather and transport the gas to market. Some shale gas is located in traditional gas producing areas, but some is not. Where new pipelines are being proposed in areas where pipelines have never been built before, or at least not recently, the public may be understandably concerned about the potential impacts of having a natural gas pipeline and appurtenant facilities nearby. The ability of the public to obtain information about proposed pipeline construction projects or to participate in the approval process depends on the type of pipeline that is being constructed. As previously noted, production, gathering, and intrastate transmission pipelines are subject to state jurisdiction. There may or may not be a formal construction review process for such pipelines. Because production and gathering pipelines tend to be low pressure pipelines, they generally cause less public 197

concern than high-pressure transmission lines. In states where there is no formal review process by the state regulatory commission, there may be no public notice of the construction at all. There may be no opportunity for the public to obtain any information about the project or become involved with issues such as siting. In such cases, only affected landowners would be aware of the proposed construction. Even when no formal permission from a state regulatory agency is required, a pipeline company may not lay a pipeline without permission to do so from the affected landowners along the entire pipeline route. Usually, a company representative will contact the landowner, describe what the company wants, and make an offer for the use of a strip of land 50 to 100 feet wide, depending on the type of pipe. This right-of-way or easement is a formal property document filed at the courthouse with other real property documents that authorizes the pipeline to use a specified parcel of land for a specified purpose for a specified term of years. The landowner can negotiate with the company over the terms of the right-of-way or easement, including the location, price, and duration. However, if the landowner refuses to negotiate, that does not mean that the pipeline will not be constructed over the landowner’s land. In most if not all states, pipelines have the right of eminent domain to acquire property to lay their pipelines. This is accomplished through a state court proceeding, where the burden of proof to establish the value of the right-of-way or easement is likely to be on the landowner.

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High-pressure interstate natural gas pipeline facilities tend to cause the most public concern. As previously noted, the FERC has an established process for certificating such pipelines, and the FERC requires that there be public notice of the pipeline’s proposal. The pipeline company is required to publish notice of its proposed construction in local newspapers all along the pipeline route. The company is also required to notify all affected landowners, including landowners whose property abuts the proposed right-of-way, is within onehalf mile of proposed compressors, or contains a residence within 50 feet of a proposed construction work area. The pipeline company will also be conducting scoping meetings to discuss the pipeline project, and there must be public notice about the scoping meetings. This means that a member of the public is likely to have actual notice that a new interstate pipeline is being proposed. WHAT ARE THE OPPORTUNITIES FOR PUBLIC INVOLVEMENT IN A FERC CERTIFICATE PROCEEDING? There are several ways that members of the public can participate in the certificate process at FERC. It is important to get involved early. If a pipeline company is conducting a scoping meeting in a community, then concerned citizens should attend. This is the first opportunity to obtain information about the project and its potential impacts. Further, the level of citizen participation in the scoping meeting will help the pipeline decide whether it should ask the FERC to open a prefiling docket. Members of the public can also request the 199

pipeline to initiate the prefiling process, although it is up to the pipeline whether it decides to do so. During the prefiling process, the pipeline will be conducting scoping meetings and making its draft environmental reports available to the public. This provides more opportunity for the public to become informed about the project, ask questions, and explore whether modifications to the project might be appropriate. It is always easier to make changes earlier in the process than later. The next opportunity for public involvement occurs once the formal application is filed. The FERC’s Federal Register notice will provide the deadline for filing a motion to intervene, which makes the filer a party to the certificate proceeding. If a person or entity wants to have the ability to file a request for rehearing of the FERC order on the certificate application or to challenge the FERC’s order in court, then that person or entity needs to file a motion to intervene and become a party to the proceeding. A motion to intervene may also include comments or a protest. If the person or entity only wants to file comments on the pipeline’s proposal, and does not wish to formally become a party, that is also permissible. The FERC’s certificate order will consider and address all comments filed, whether or not the filer is a party to the proceeding. After the FERC publishes notice of the application, the FERC will conduct scoping meetings to determine the environmental issues associated with the proposal. Representatives of the pipeline will also be in attendance. This provides opportunities for interested members

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of the public to ask questions and place their concerns in front of the FERC staff for consideration at an early phase of the proceeding. The next public input opportunity occurs after the FERC issues the draft EIS or EA. The FERC provides a public comment period of at least 30 days. After the FERC issues its order approving or denying the project, parties to the proceeding may file for rehearing of the FERC order and pursue court appeals. Commenters do not have these rights. What Criteria Does the FERC Use to Evaluate a Project? In order for a member of the public to determine how best to become involved in a pipeline certificate application, it is helpful to understand how the FERC evaluates certificate applications. The 1999 Policy Statement is the latest expression of the FERC’s policy. Under the Policy Statement, the threshold requirement for an applicant to establish is that the new pipeline can be constructed without subsidization by existing customers. The “no subsidy” prong is generally satisfied by pricing the services to be rendered through the new facilities on an incremental basis, i.e., the cost of transportation through the new pipeline is based on the construction cost of the new pipeline. Assuming this requirement is satisfied, then the FERC considers whether the applicant has made efforts to eliminate or minimize adverse effects on the applicant’s existing customers, 201

existing pipelines in the market and their captive customers, and landowners and communities affected by the construction. If there are residual adverse effects on these interest groups after efforts have been made to minimize them, the FERC will evaluate the project by balancing the evidence of public benefits to be achieved against the residual adverse effects. This is essentially an economic test. Only when the benefits outweigh the adverse effects on economic interests does the FERC proceed to environmental analysis of the project. The FERC’s environmental analysis of the application starts with the company’s environmental report submitted as part of the certificate application. But the FERC conducts its own environmental review to prepare the EA or EIS with the assistance of a third-party environmental consultant contractor, which the FERC selects and the applicant pays for. The FERC’s environmental review is thorough and addresses all comments received by government agencies and members of the public. If the EA or EIS results in a finding of no significant impact, then it is fairly certain that the FERC will approve the project. The environmental review may also reveal that an alternate route is environmentally preferable for the project to avoid sensitive areas or mitigate environmental impacts, in which case the FERC order on the application is likely to condition approval of the application on use of the alternate route or certain mitigation measures. Issuance of a certificate of public convenience and necessity by FERC does not mean the applicant may commence construction immediately. The FERC order may be issued before the applicant has received other 202

required federal agency approvals. The environmental conditions attached to the FERC order will require that all such approvals be obtained prior to the commencement of construction. The applicant will have to obtain written authorization from the FERC’s Director of the Office of Energy Projects to commence construction. If the applicant receives all of the requisite permits but has not been able to acquire all of the necessary rights-ofway or easements through negotiation, the applicant can exercise eminent domain to acquire the land rights. The NGA confers eminent domain authority on holders of a FERC construction certificate. Case Study A recent FERC order is illustrative of the FERC’s approach to certificating a pipeline project in the face of significant public opposition.16 In that proceeding, the pipeline company proposed to put a compressor station close to a small Maryland town, next to a wastewater treatment plant and gas station, and adjacent to an interstate highway. A compressor station is an aboveground facility, and is used to facilitate movement of gas through the pipeline. As previously noted, compressor stations are spaced along the route of the pipeline. The towns-folk vigorously protested the location of the compressor station in their town. More than 650 individuals filed comments opposing the proposed location, contending it was incompatible with their rural community and would result in irreversible damage to their quality of life. Concerns were also expressed with respect to construction traffic, road damage/repairs, and 203

dust, as well as operational aspects of the compressor station, such as noise. The FERC order explained that FERC looked at eight alternative compressor sites in addition to the pipeline’s proposed site. Three were eliminated due to engineering requirements. Three others were eliminated due to constructability and/or residential impact issues. The FERC also considered a pipeline looping alternative and an electric compression alternative. The two remaining alternative sites were thoroughly analyzed in the EA, and the FERC determined that the proposed site offered environmental advantages the two alternatives did not. Accordingly, the FERC order approved the applicant’s proposed compressor station site. Instructive findings by the FERC include: 1. Need for the project. Because the capacity of the proposed project was fully subscribed, the FERC concluded there was a need for the pipeline, including the compressor station. 2. Town’s rejection of zoning request. The FERC stated that while it encourages cooperation between pipeline companies and local authorities, this does not mean that state or local laws can be used to prohibit or unreasonably delay construction or operation of FERC-approved facilities. FERC stated, “While applicants may be required to comply with appropriate state and local regulations where no conflict exists, state and local regulation is preempted by the NGA to the extent they conflict with federal 204

regulation, or would delay the construction and operation of facilities approved by this Commission.”17 3. Air permits. Compressor stations require Clean Air Act permits. These are federal permits, but are administered by the state environmental agency if the state has a federally approved state implementation plan. The FERC declined to address air quality permit issues because they are outside the FERC’s jurisdiction, but noted that the EA concluded that air impacts would be within environmentally acceptable limits. The FERC further noted that its order was conditioned on the pipeline company obtaining all applicable authorizations required under federal law. Thus, if the state of Maryland did not issue the air quality permit, it would be up to the pipeline company to determine how to proceed. 4. Unavailing arguments. The FERC considered and dismissed arguments raised concerning the following: impact on historical properties (none); visual impacts (sufficiently mitigated); property values (subjective and adequately mitigated through visual screening and noise mitigation measures); economic issues (speculative); air quality impacts (compliance with federal and state air quality regulations are required by the order); noise impacts (mitigation adequate); public safety (adequate control systems, compliance with safety regulations required); landowner impact (FERC declined to expand the impact zone beyond the one-half mile radius required by FERC regulations); water quality (adequate mitigation, plus compliance with the Clean Water Act is required by 205

the order); invasive species (adequate mitigation); and migratory birds (no adverse effect). It can be expected that because FERC does a thorough environmental review, the FERC’s order will defend the conclusions of the EA or EIS against challenges. Further, if the FERC finds that adverse impacts can be mitigated through adoption of reasonable measures such as planting trees or installation of sound control equipment, then the FERC is not going to be receptive to concerns about such adverse impacts. This means that any project concerns should be communicated to the FERC early on, before the final EA or EIS. The FERC might not agree with the concerns expressed, but the FERC will consider and respond to them. This provides the concerned citizen with the maximum opportunity to be heard. Many of the Maryland citizens were generally opposed to the compressor station on generic quality of life grounds. In essence, these are “not in my back yard” arguments. The FERC is not receptive to these sorts of complaints. Local opposition will not deter the FERC from its mission, which is to evaluate the pipeline project in accordance with FERC’s policies and regulatory requirements. The bottom line is that a concerned citizen may not have the ability to prohibit certification of an interstate pipeline, but he or she will have the opportunity to express his or her concerns and have them addressed in the certificate proceeding. Public input may cause the FERC to require the applicant to take measures to minimize adverse impacts associated with construction

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and/or operation of the pipeline and associated facilities. Active participation early in the project may even influence the siting of an interstate pipeline facility if there are environmental issues that can be mitigated though relocation. For these reasons, it is worthwhile for members of the public to become involved in FERC certificate proceedings. The public interest is advanced when pipeline projects are subjected to vigorous examination. NOTES 1. Natural gas can be converted to a liquid by cooling the gas to approximately –260 degrees Fahrenheit. Liquefied natural gas, or LNG, takes up 1/600th the space of natural gas at atmospheric pressure. In this condensed form it can be stored in above-ground storage tanks until it is needed, at which time it is regasified for transportation in pipelines. LNG can also be shipped in special tankers across the oceans to LNG storage tanks and regasification terminals in other countries. 2. Section 1(c) of the NGA, 15 U.S.C. § 717c, contains an additional exemption from federal regulation for intrastate pipelines that receive their gas supplies within or at the boundary of a state and all the gas is ultimately consumed within such state, provided that the rates and services provided by such pipelines are subject to regulation by a state commission. 3. The Department of Energy’s Office of Fossil Energy, or DOE/FE, is responsible for approving imports and 207

exports of natural gas, including LNG, but FERC has jurisdiction over the siting of natural gas pipelines used to import or export natural gas, and the siting of LNG terminals. 4. Am. Petrol. Inst., AMERICAN PETROLEUM INSTITUTE RECOMMENDED PRACTICE 80: GUIDELINES FOR THE DEFINITION OF ONSHORE GAS GATHERING LINES, (1st ed., Apr. 2000) [hereinafter API RP 80]. 5. API RP 80 at Section 2.4.4. 6. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration, or PHMSA, has jurisdiction over pipeline safety and integrity. Production pipelines are not presently subject to PHMSA regulation. 7. Natural Gas Act of 1938 § 1(b), 15 U.S.C. § 717b. 8. In contrast, federal regulation over pipeline safety starts with gathering pipelines. PHMSA’s regulations generally define the term “gathering line” as “a pipeline that transports gas from a current production facility to a transmission line or main.” Under the PHMSA regulations, the pipeline operator must determine whether a pipeline is a gathering line by consulting API RP 80, then applying additional considerations and limitations imposed by the PHMSA regulations.

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9. See, e.g., Stingray Pipeline Co., LLC, 142 FERC ¶ 62,069 (2013). 10. Processing plants are not subject to FERC jurisdiction under the NGA. 11. Under Section 311 of the Natural Gas Policy Act, however, intrastate pipelines may participate in interstate transportation without becoming interstate pipelines subject to the full panoply of FERC jurisdiction, so long as they follow the FERC regulations and policies applicable to Section 311 service. 12. LNG terminal facilities are subject to FERC siting regulation, but not all LNG terminals are subject to rate regulation. 13. NGA § 7(c). 14. Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC ¶ 61,277 (1999). 15. This pamphlet, called, AN INTERSTATE NATURAL GAS FACILITY ON MY LAND? WHAT DO I NEED TO KNOW? can also be downloaded from the FERC website, www.ferc.gov. 16. Dominion Transmission, Inc., 141 FERC ¶ 61,240 (2012). 17. Id. at P 68.

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6 Anticipating Problems Road Agreements, Enforcement

Performance

Bonds,

and

Heather M. Urwiller

Local

governments must balance the needs of job creation and economic development with the responsibility to protect the health, safety and welfare of local residents and stakeholders. As detailed in chapter 11, the activities that accompany unconventional oil and gas development can have significant impacts on roads, public safety, emergency responder workload, and other public services. Municipalities are primarily responsible for providing these services and must budget for them in their staffing and tax plans. They are implementing strategies to protect themselves from unfunded liabilities in the face of rapid development of oil and gas. Municipalities have long used road agreements and proof of insurance and performance bonds to manage negative impacts of many kinds of development and are now tailoring these tools for use with oil and gas development. This chapter will use case studies to illustrate how these tools can be used to maintain some control over the impacts of oil and gas development activity.

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Performance bonding, insurance requirements, and road agreements can be used to ensure that municipalities are able to address adverse conditions that could arise as a result of oil and gas development. Performance bonds are often used to ensure that developers comply with state and local regulations. Road maintenance agreements are specifically applicable to jurisdictional highways—often the greatest percentage of local appropriations and expenditures in rural municipalities.1 PERFORMANCE BONDS Performance bonds are a useful instrument to protect communities against abandonment of projects and to ensure compliance with preapproved development plans. Typical examples of areas outside of oil and gas development where bonding is commonly employed include projects like subdivision development and extraction of sand and gravel. In oil and gas drilling, performance bonds are required by local governments to guarantee that drilling and reclamation of wells is done in compliance with both state and local permit requirements. Should a drilling company fail to restore a well site, the cost of reclamation could potentially bankrupt a small community (not to mention a landowner), and bonds can help to indemnify the community (or individual) against such costs. The bonds are generally delivered to the municipality by drilling operators as the final step in the permit process before drilling commences. Bond amounts can range from a few thousand dollars to over a million dollars. For 211

example, the City of Pine Haven, Wyoming, requires both a minimum surety bond of $200,000 and a one million dollar bond or policy of liability insurance to cover hazardous accidents, including blowout preventer malfunctions. In addition, the applicant must carry standard public comprehensive liability coverage.2 For additional examples of communities that require bonding or insurance provisions, see Tables 6.1 and 6.2. Performance bonds are generally held by the municipality until the well sites are completely reclaimed. Defined criteria and performance measures often must be achieved before the bonds are released by municipalities. Performance measures may include total reclamation, partial site reclamation, satisfactory water quality tests, or other environmental measures. Operators may request, and municipalities often grant, partial bond releases upon completion of stages of reclamation. This type of practice is especially important in the context of industries, such as unconventional oil and gas development, where accidents and negligence can result in extreme impacts to communities and stakeholders. Most state governments also require bonding by oil and gas companies. Table 6.3 provides statutory locations of state bonding requirements.

Table 6.1. County Government Efforts to Regulate Oil and Gas Development

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COUNTY ACTIONS TAKEN

SOURCE

Garfield Draft http://www.oilandgasbmps.org/law/ County, regulation and colorado_localgovt_law.php Colorado Oil and Gas http://www.garfield-county.com/oil-gas/ Department. index.asp Permits for overweight vehicles are required Gunnison Regulations http://www.oilandgasbmps.org/law/ County, for well colorado_localgovt_law.php Colorado facilities and http://www.gunnisoncounty.org/ include planning_regulations_guidelines.html#Oil_Gas requirement to pay mitigation for impact of operations La Plata Regulation of http://www.oilandgasbmps.org/law/ County, well facilities colorado_localgovt_law.php Colorado and http://www.co.laplata.co.us/ differentiate departments_and_elected_officials/planning/ between natural_resources_oil_gas minor and major facilities &

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impacts must be mitigated Pitkin Regulation of http://www.oilandgasbmps.org/law/ County, oil and gas colorado_localgovt_law.php Colorado facilities and include provisions to protect Roads and Access Saguache Regulation of http://www.oilandgasbmps.org/law/ County, oil and gas colorado_localgovt_law.php Colorado well facilities and include Road Access and Transportation Route Plans Yuma Regulation of http://www.oilandgasbmps.org/law/ County, oil and gas colorado_localgovt_law.php Colorado well facilities and include Road/ Improvement Agreements

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Duchesne Oil and Gas http://www.oilandgasbmps.org/law/ County, drilling utah_localgovt_law.php Utah requires a conditional use permit and road permits, encroachment permits are required and County must be named as an additional entity on State required performance guarantees Emery County, Utah

Oil and Gas http://www.oilandgasbmps.org/law/ Wells require utah_localgovt_law.php a conditional use permit and a road encroachment permit

Grand County, Utah

Oil and Gas http://www.oilandgasbmps.org/law/ Wells require utah_localgovt_law.php extensive review of haul route,

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restriction maybe placed on haul routes and operator are restricted to daytime

Source: Intermountain Oil and Gas BMT Project: Getches-Wilkinson Center for Natural Resources, Energy and the Environment/University of Colorado Law School http://www.oilandgasbmps.org/laws/index.php.

Table 6.2. City Government Efforts to Regulate Oil and Gas Development CITIES

ACTION TAKEN

SOURCE

Gillette, City has insurance http://www.oilandgasbmps.org/law Wyoming requirements and speaks to http://www.ci.gillette.wy.us/Modul maintaining of roads. All ShowDocument.asp?documentid=5 loads are to be within limitation set by city and average load weights and number of projected loads

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are to be included as part of application

Pine City requires a statement a http://www.oilandgasbmps.org/law Haven, map what routes will be http://pinehaven.wy.govoffice2.com Wyoming utilized for transportation of BASIC&SEC={68E82548-2404-4 equipment and supplies and approximate weight of each load. All loads shall be within weight limits set by city. Fort Worth, Texas

City regulates oil and gas http://forthworthtexas.govuploaded wells through permitting 09012_gas_drilling_final.pdf Truck routing information must be provided including both use of commercial and non-commercial routes along with a road agreement

Arlington, City requires payment of a http://www.arlingtontx.gov/plannin Texas road damage fee based on Final_Gas_Drilling_Amendments_ the City’s Road Damage Assessment. The fee is calculated using a formula.

Aurora, Oil and Gas Facilities in the http://library.municode.com/index. Colorado city Ch. 146, Art 2, Sec. 7 (146-1207):

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Lafayette, Oil and Gas Development §26.22-1: Colorado specific standards for road index.aspx?clientID=10101 and road access agreements required Louisville, Oil and Gas Regulations Ch. Thornton, Colorado Colorado 17.68: http://library.municode.com/ index.aspx?clientID=13149

Source: Intermountain Oil and Gas BMT Project: Getches-Wilkinson Center for Natural Resources, Energy and the Environment/University of Colorado Law School http://www.oilandgasbmps.org/laws/index.php.

Many municipalities are not satisfied with state bonding requirements for oil and gas operators and with increasing frequency are requiring bonds and liability insurance beyond what states mandate. Table 6.1 provides examples of county governments that require local bonds. Table 6.2 provides examples of cities that require bonds as part of the local permit application. Some municipalities are more aggressive than others in the type of insurance and bonding they require operators provide to secure a local well drilling permit. In Colorado, Gunnison and Mesa Counties have explicit requirements for financial security,3 which is usually accomplished 218

through bonds or letters of credit. In contrast, Campbell County, Wyoming, has no bonding requirements in relation to oil and gas well development.4 INSURANCE While most operators carry a variety of insurance—whether it is required or not—municipalities are increasingly requiring operators to carry additional insurance to further indemnify the community against potential loss and increase compliance. Insurance protects the operators, landowners, and municipalities from catastrophic loss if something unintended occurs on the well site. For instance, chapter 12 of the Oil and Water Well section of the city of Gillette’s code requires applicants to a provide a minimum of one million dollars in liability insurance and deposit $16,500 in lawful currency, letter of credit or surety bond for each well. Any violation of the permits results in the forfeiting of the deposit.5 ROAD MAINTENANCE AGREEMENTS Bonding requirements can be extended to road maintenance. Many municipalities include provisions in drilling applications that allow the use of bonds, letters of credit or insurance claims to pay for damage to local infrastructure. Municipalities commonly use road agreements for trucking and distribution facilities, commercial wind farms, and large commercial and industrial campuses. Municipalities have extended these common provisions from more conventional types of

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local development to unconventional oil and shale gas development.

Table 6.3. Oil and Gas Regulations in Various States STATE

STATE MAJOR SOURCE REGULATORY REGULATIONS AUTHORITY

Pennsylvania Pennsylvania Title 58, 78, 79, http://www.portal.state.p Department of 91, 95 & 102 PA oil_and_gas/6003 Environmental Consolidated http://www.portal.state.p Protection Statutes law%2C_regulations_gu http://www.legis.state.pa 58.HTM Texas

Railroad Commission Texas

Chapter 52, 71, http://www.statutes.legis of 81, 85,86, & 89 http://www.rrc.state.tx.u TX Natural Resources Code

Colorado

Colorado Oil & Title 34 Colorado http://www.legisnexis.co Gas Conservation Revised Statutes http://www.oilandgasbm Commission http:cogcc.state.co.us

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Utah

Utah Division of Title 40 Oil, Gas & Statutes Mining

Utah http://le.utah.gov/Utah c http://www.oilandgasbm http://linux1.ogm.utah.g tabs/html

Louisiana

Department Natural Resources

Wyoming

Wyoming Oil Title 30 Chapter 5 http://legisweb.state.wy. and Gas Wyoming Code http://www.oilandgasbm Conservation http://wogcc.state.wy.us Commission

Montana

Montana Board Title 82, Chapter http://data.opi/mt.gov/bi of Oil and Gas 10-11 Montana http://www.oilandgasbm Conservation Code http://bogc.dnrc.mt.gov

of Titles 30 and 31 http://www.legis.la.gov/ Revised Statutes laws_toc.aspx?folder=75 http://dnr.louisiana.gov/ index.cfm?md=pagebuil

Source: Intermountain Oil and Gas BMT Project: Getches-Wilkinson Center for Natural Resources, Energy and the Environment/University of Colorado Law School, http://www.oilandgasbmps.org/laws/index.php.

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Roads are built to specific standards, and heavy loads that exceed design standards can cause the failure of the road surface as well as bridge collapse. Many local roadways and bridges are not designed to handle large volumes of overweight loads, posing logistical and compliance problems for operators. Road failure can lead to costly road reconstruction or redesign. Even modest increases in this type of traffic can severely impact local communities. If developers and operators of well sites are not monitored for their impacts on roadways, the municipality can be forced to bear costs associated with road damage—costs that, were they anticipated, can be avoided or minimized. To avoid or minimize these problems, operators are generally required to get permits at both the state and local level for overweight vehicles. Where prevention does not suffice to avoid damage, carefully executed road agreements can help to ensure repair or replacement of road surfaces or bridges in the event they are damaged due to a developer’s actions. Road impacts include not only damage to road surfaces but include broad impacts on road right of ways like concentrated traffic requiring road improvements. Concentrating traffic can require the following types of improvements: road widening, vertical realignment of highways to improve grades for heavy vehicles, horizontal realignment of highways to accommodate curve radii for large vehicles, drainage improvements associated with road widening and/or vertical/horizontal realignments, or legal and property rights transactions associated with temporary or permanent property 222

acquisitions or easements.6 Road agreements are common in any type of extractive use. The local municipality will review the developer’s application and determine the loading and types of equipment that will be hauled on local roadways. The agreements generally delineate preferred or required truck haul routes and define the maximum number and weight of truckloads in the haul route schedule. Because these costs can be significant, many local communities are working with the industry on issues related to road conditions by, for example, requiring that industry use designated truck haul routes and estimate weight and number of loads. Tables 6.1 and 6.2 provide information on counties and cities currently requiring road impacts to be addressed as part of the drilling permit process. Deliberate use of haul routes and other best management practices can protect operators and their subcontractors from being forced to provide new road surfaces. Drilling and fracturing processes are temporary and intermittent. Therefore, when best management practices are used, operators need not provide costly repairs to infrastructure. Yuma County and Pitkin County, Colorado, both require road agreements as part of the permit application process (see Table 6.1). The agreements generally look at the prior conditions of roadways, truck hauling routes, and the number and average weight of overweight loads. Both communities also require overweight vehicle permits and local road or encroachment permits.

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The cities of Lafayette, Wyoming, and Forth Worth, Texas, require road agreements as part of the permit application process (see Table 6.2). These communities look at the impact of overweight vehicle and truck haul routes on local roadways. The city of Arlington, Texas, has a different approach. It has adopted a road damage fee based on the City’s Road Damage Assessment (see Table 6.2), which are used to pay for improvements to local roadways. Fees are calculated based on access of lane mile for appropriate road type, assessment per land mile, and number of lane miles included in each gas permit.7 Enforcement against violators of permits or posted weight limits is an additional mechanism used to deter road damage and raise dollars to fund repairs. In addition to permits, Caddo Parish, Louisiana, has successfully used fines for overweight vehicles and other penalties in an effort to stem road damage. According to the parish attorney, the parish determined early in the shale gas boom that revenue from fines would exceed permit fees for overweight vehicles transporting materials to and from well sites. Over time the parish has seen a reduction in the number of fines as truck haulers and operators increase compliance with local laws and seek permits prior to moving materials to and from well sites. By requiring permits, the parish can provide guidance to operators and truck haulers on which roads and routes to use for overweight vehicles. This minimizes the damage that operators must repair.8 Some states, like Pennsylvania, have taken unique approaches to provide resources for infrastructure maintenance and repair. Title 58 of the Pennsylvania 224

Consolidated Code allows counties to levy well fees specific to unconventional gas wells. If counties opt out of levying these additional fees, local municipalities are authorized to levy the fee.9 This unconventional well fee is in addition to any local application fees or state taxes. The fees collected are used to support a variety of state goals, such as providing additional funds to the state’s road and bridge program and improving environmental quality and stewardship among local communities that have active unconventional oil and gas resources extraction. As unconventional oil and gas development expands, local communities will have to work with operators to develop provisions to protect infrastructure and foster environmental stewardship. Damage from nonperformance and/or accidents can be anticipated and mitigated through the use of bonding and insurance requirements. Road agreements and regulation can put the onus on the industry to repair infrastructure damage caused by shale oil and gas exploration and development. While this development brings some new challenges, many of the types of impacts are similar to those experienced with any large-scale extractive industry; the tools available to municipalities for dealing with these issues—bonding, insurance requirements, and contractual agreements governing infrastructure use—are variations on tools that municipalities have been using for a long time. NOTES

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1. Author’s personal communication with Adam Yagelski (May 2013). 2. For Pine Haven, Wyoming, local insurance provisions see: http://www.oilandgasbmps.org/law/ utah_localgovt_law.php and http://pinehaven.wy.govoffice2.com/ index.asp?TYPEBBASIC&SEC={68E82548-2404-4AE9-BD74-C2E91A178F69}. 3. For Gunnison County and Mesa County, Colorado, ordinance provisions see: http://www.oilandgasbmps.org/law/ colorado_localgovt_law.php. 4. Conversation with Building and Planning Department Staff, Campbell Cnty., Wyo. (May 9, 2013) (verified that the County does not have bonding requirements for oil and gas development). 5. Gillette, Wyoming: Chapter 12 Oil and Water Wells provision B and D cover the liability insurance and additional surety requirements: see http://www.oilandgasbmps.org/law/ wyoming_localgovt_law.php. Cities are discussed at the bottom of the page. 6. C. J. Randall, Hammer Down: A Guide to Protecting Local Roads Impacted by Shale Gas Drilling (Working Paper Series: A Comprehensive Economic Impact Analysis of Natural Gas Extraction in the Marcellus Shale, 2010),

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available at http://www.greenchoices.cornell.edu/ downloads/development/shale/marcellus/ Protecting_Local_Roads.pdf (citing, in a broad way, considerations pertaining to preparing and implementing a “comprehensive traffic impact study”). See also Powerpoint: Delta Engineers, Architects, & Land Surveyors P.C., Delta Road Protection Program (June 24, 2011), available at http://www.co.chenango.ny.us/planning/education/ documents/AOTC/ Marcellus%20Roads%20-%20Messmer%20Delta%20Eng.pdf (Chenango County from the Engineering Company—see the map of participating towns at the end); Oneonta, N.Y., Local Road Use and Preservation Law, Local Law No. 3 (2012), available at http://townofoneonta.org/site%20elements/ LocalLawNo3_2012.pdf (implementing legislation). 7. Arlington, Tex., Ordinance No. 11-068, § 5.01(I) (Dec. 6, 2011). See Arlington, Tex., Ordinance No. 07-074 (Oct. 23, 2007), available at http://www.arlingtontx.gov/planning/pdf/Gas_Wells/ Final_Gas_Drilling_Amendments_Ordinance.pdf. 8. Telephone Conversation with Charles Grugg, Attorney, Caddo Parish, La. (Apr. 1, 2013). As part of the permit process operators, and contractors must seek approval for the routes used by trucks for construction and well drilling. The Parish takes video evidence to road conditions prior to well development. Operators are held accountable for any damage to roads and bridges and required to repair damage. The Parish, through enforcement of the laws, uses fining and prior 227

permitting as a means to control damage to public infrastructure. “They have found this to be effective.” The Parish employs a full time employee who has a portable scale that he tows around, using random truck weighing to enforce the overweight truck regulations. The enforcement is mean to collect fines from crossstate independent haulers. The employee patrols the back roads looking for violators. The Parish determined early in the shale gas boom that revenue from fines would exceed permit fees for vehicles transporting materials to and from well sites. Over time, the Parish has seen the number of fines decrease as haulers and operators become more compliant and seek permits prior to moving materials to and from well sites. The permitting process allows the Parish to provide guidance to operators and haulers on which roads and routes to use for overweight trucks, minimizing damage that operators must repair. 9. Unconventional Gas Well Fee, 58 Pa. Const. Stat. §§ 2301–2318, available at http://www.legis.state.pa.us/ WU01/LI/LI/CT/HTM/58/58.HTM.

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7 Clearing the Air Reducing Emissions from Unconventional Oil and Gas Development Beth E. Kinne

The debate on air pollution impacts from unconventional gas development via hydraulic fracturing has focused on two related yet quite distinct areas. The first involves broader climate impacts that may be geographically and temporally removed from the locus of drilling activity. The second, which involves the health impacts of more or less immediate localized exposure to pollutants such as volatile organic compounds, ground level ozone, and smog, is the primary focus of this chapter. In response to these concerns, some state governments, such as Colorado, Wyoming, Texas, and Pennsylvania, and more recently the U.S. EPA, have promulgated regulations aimed at reducing emissions of air pollutants from oil and gas wells (see state-by-state discussion below). Industry has also developed new technologies to reduce emissions. Many of these changes have enabled the capture of significant amounts of valuable hydrocarbons, resulting in economic gains and reasonably short payback periods. The willingness of industry and

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regulators to embrace advances in technology and work practices will shape the overall impact of oil and gas development on air quality, public health, greenhouse gas emissions, and the public’s perception of the industry and regulators. This chapter begins with an overview of the types of air pollution created by oil and gas drilling. It then addresses the human health and air quality concerns created by oil and gas development, particularly from unconventional drilling. This is followed by a discussion of some key technologies available to reduce emissions. The final section explains some voluntary initiatives and regulations that are promoting the use of these key technologies and provides some examples of air quality monitoring programs that are being used to better understand emissions from oil and gas development. AIR POLLUTION FROM OIL AND GAS DRILLING Known air pollutants associated with hydraulic fracturing activities include particulate matter, methane, and a variety of other volatile organic compounds (VOCs), including benzene, toluene, ethylbenzene, and xylene, which are sometimes collectively referred to as BETEX or non-methane hydrocarbons (NMHCs).1 When combined with sunlight, water, and nitrogen oxides (the primary source of which is combustion of diesel fuel by large trucks and generators at the well pad site), VOCs create ground-level ozone, which has well-documented consequences for human and plant health. The oil and gas

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industry is the largest industrial emitter of VOCs, emitting an estimated 2.2 million tons in 2008.2 Natural gas development is frequently not the only exposure pathway to these chemicals for most people. For example, people are regularly exposed to small amounts of benzene from motor vehicle exhaust, tobacco smoke, and many solvents, paints, and detergents.3 However, long-term, chronic, high-level exposure in areas experiencing intensive development can significantly impact human health and the quality of life of gas industry workers and of individuals living near these operations.4 Data on fugitive methane emissions from oil and gas production is somewhat limited, although recent studies are contributing significantly to the creation of a more comprehensive understanding of this issue.5 However, fugitive emissions have been documented during the drilling process, during completion (the period of time after the well is drilled, but before it is attached to a production line), and from compression, transmission, storage, and consumer distribution processes.6 During drilling of the well, emissions from the target layer and/or other shallower layers may escape.7 In addition, if flowback is returned to open pits, volatile compounds can evaporate from those pits into the air. Steps used to maintain the productivity of the well can also result in fugitive emissions. Over the life of the well, smaller amounts of water continue to be produced along with the gas. After a well has been in production for some 231

time, the rate of gas flow declines as the pressure in the system is reduced. Water can build up in the wellbore and reduce the productivity of the well. In these cases, taking the well offline to vent it to atmospheric pressure can allow the pressure of the gas to lift the accumulated water out of the well in what is called well deliquification or “blowdown.” The EPA estimates that 9.6 Bcf of methane per year is lost during well blowdowns.8 During this process, the gas must be either vented (released) to the atmosphere or flared (burned on site), thus producing either methane (with venting) or carbon dioxide (with flaring). Methane and other hydrocarbons can be captured using specialized equipment. Alternative technologies to blowdown are available (as detailed below) and can significantly reduce air emissions. Releases can also occur at many other points along the process as well, either from leakage (fugitive emissions) or by design (venting). For example, faulty construction and wear and tear can result in fugitive emissions from pipeline connections, valves, compressor stations, and storage facilities. Routine maintenance and repair activities often require depressurization of a component of the system, which can be quickly and easily accomplished by venting. The EPA’s 2011 Greenhouse Gas Inventory Report, released in spring 2013, reported that overall emissions from natural gas systems (including production, transmission, storage, and distribution) decreased by 10.2 percent between 1990 and 2011.9 Recent research tracking actual emissions of air pollutants by the oil and gas industry and industry-reported emission reductions 232

under the EPA Natural Gas STAR program (discussed below) suggest that losses of methane, benzene, and other compounds may be significantly underestimated in both industry and government studies.10 Currently, over 20,000 oil and gas wells are hydraulically fractured or re-fractured each year.11 While some states, such as Colorado,12 are utilizing increased setbacks to reduce risks presented by gas drilling, setbacks alone will likely be insufficient to mitigate chronic exposure of the public from cumulative sources over long periods of time and will certainly not reduce workers’ exposure to these pollutants.13 HEALTH IMPACTS OF EMISSIONS FROM OIL AND GAS DRILLING In a recent policy statement, the American Public Health Association asserted, “The onset of HVHF in many parts of the country represents a new industrial, environmental, and land use development pattern with significant potential for impacts on public health.”14 As development of unconventional shale plays for oil and gas expands, the number of wells hydraulically fractured annually will likely rise. Increases in oil and gas development near urban and suburban populations will result in increased exposure rates unless emissions are reduced by the application of appropriate technology and work practices. While drilling activity could affect health in multiple ways, air pollution concerns mainly include ground-level ozone, particulate matter, and air toxics. Ground-level ozone is a very strong oxidant. It is damaging to lung tissue and can have particularly 233

significant impacts on children, the elderly, and people who spend a lot of time outdoors. The EPA states that ground-level ozone “is linked to a wide range of health effects, including aggravated asthma, increased emergency room visits and hospital admissions, and premature death.”15 When ground-level ozone combines with small particulates (